20230201Kinney Exhibit 6 Schedule 1-6.pdf

DAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL FOR
REGULATORY & GOVERNMENTAL AFFAIRS
AVISTA CORPORATION
P.O. BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-3727
TELEPHONE: [phone]
[e-mail]
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. AVU-E-23-01
CASE NO. AVU-G-23-01
EXHIBIT NO. 6
OF
SCOTT J. KINNEY
(ELECTRIC AND NATURAL GAS)
2021 Electric
Integrated Resource Plan
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 1 of 317
Safe Harbor Statement

This document contains forward-looking statements. Such statements are subject to a
variety of risks, uncertainties and other factors, most of which are beyond the Company’s
control, and many of which could have a significant impact on the Company’s operations, results of operations and financial condition, and could cause actual results to differ materially from those anticipated.

For a further discussion of these factors and other important factors, please refer to the
Company’s reports filed with the Securities and Exchange Commission. The forward-looking statements contained in this document speak only as of the date hereof. The Company undertakes no obligation to update any forward-looking statement or
statements to reflect events or circumstances that occur after the date on which such
statement is made or to reflect the occurrence of unanticipated events. New risks,
uncertainties and other factors emerge from time to time, and it is not possible for management to predict all of such factors, nor can it assess the impact of each such factor on the Company’s business or the extent to which any such factor, or combination of
factors, may cause actual results to differ materially from those contained in any forward-
looking statement.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 2 of 317
Production Credits

Primary Electric IRP Team
Clint Kalich Mgr. of Resource Planning & Analysis IRP Core Team
James Gall IRP Manager IRP Core Team
John Lyons Sr. Policy Analyst IRP Core Team
Lori Hermanson Sr. Power Supply Analyst IRP Core Team
Grant Forsyth Chief Economist Load Forecast
Ryan Finesilver Mgr. of Energy Efficiency, Planning & Analysis Energy Efficiency
Leona Haley Energy Efficiency Program Manager Demand Response

Electric IRP Contributors
Scott Kinney Director of Power Supply Power Supply
Chris Drake Wholesale Marketing Manager Power Supply
Thomas Dempsey Mgr. Thermal Operations and Maintenance Resource Options
Tom Pardee Natural Gas Planning Manager Natural Gas Planning
Michael Brutocao Natural Gas Analyst Natural Gas Planning
Darrell Soyars Mgr. Corporate Environmental Compliance Environmental
Bruce Howard Sr. Director Environmental Affairs Environmental
Megan Lunney Manager Spokane River License Environmental
Tom Lienhard Chief Energy Efficiency Engineer Energy Efficiency
Damon Fisher Principle Engineer Distribution Planning
Randy Gnaedinger Transmission Contracts Analyst Transmission Planning
Dean Spratt Sr. System Planning Engineer Transmission Planning
John Gross Mgr. of System Planning Transmission Planning
Shawn Bonfield Sr. Manager of Regulatory Policy Regulatory
Amanda Ghering Regulatory Affairs Analyst Regulatory
Annie Gannon Communications Manager Communications
Ana Matthews Energy Efficiency Program Manager II Energy Equity
Renee Coelho Energy Efficiency Program Manager II Energy Equity
Shana Gail Sr. GIS Analyst Energy Equity
Robert Cloward Sr. GIS Analyst Energy Equity

Contact contributors via email by placing their names in this email address format:
[e-mail]
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 3 of 317
2021 Electric IRP Introduction

Avista has a 132-year tradition of innovation and a commitment to providing safe, reliable, low-cost, clean energy to our customers. We meet this commitment through a diverse mix of generation and demand side resources.
The 2021 Integrated Resource Plan (IRP) continues our legacy by looking 24 years into
the future to determine the energy needs of our customers. The IRP analyzes and outlines
a strategy to meet projected demand and renewable portfolio standards through energy efficiency and a diverse mix of clean generation resources.
Summary
The 2021 IRP shows Avista has adequate resources between owned and contractually
controlled generation, when combined with conservation and market purchases, to meet customer needs through 2025. New renewable energy, energy storage, demand response, energy efficiency, and upgrades to existing hydropower and biomass plants
are integral to our plan.
Changes Major changes from the 2020 IRP include:
• Retail sales and residential use per customer forecasts are slightly higher
compared to the 2020 IRP projections.
• Return of new natural gas-fired peakers because long-term energy storage is not yet available or as cost effective as initially estimated in the 2020 IRP for the 2026
capacity need.
• Demand response programs begin in 2024 and grow to 71 MW by 2045. Highlights
Some highlights of the 2021 IRP include:
• The resource strategy meets nearly 78 percent of Avista’s corporate clean energy goal to provide customers with 100 percent net clean energy by 2027 at competitive prices.
• A new chapter in this IRP addresses energy equity and details plans to form an
Equity Advisory Group in 2021 to further engage Washington’s vulnerable and
highly impacted communities.
• New renewable energy is needed in 2023 and 2024 to meet Washington’s clean
energy targets. The most viable new resource option is 200 MW of wind from
Montana. Another 100 MW of wind is added in 2028. IRP Process
Each IRP is a thoroughly researched and data-driven document identifying a Preferred
Resource Strategy to meet customer needs while balancing costs and risk measures with
environmental goals and mandates. Avista’s professional energy analysts use sophisticated modeling tools and input from over 100 participants to develop each plan. The participants in the public process include customers, academics, environmental
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 4 of 317
organizations, government agencies, consultants, utilities, elected officials, state utility
commission stakeholders, and other interested parties.
Conclusion
This document is mostly technical in nature. The IRP has an Executive Summary and
chapter highlights at the beginning of each section to help guide the reader. Avista
expects to begin developing the 2023 IRP in late 2021. Stakeholder involvement is
encouraged and interested parties may contact John Lyons at [phone] or [e-mail] for more information on participating in the IRP process.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Table of Contents

1. Executive Summary ...................................................................................................... 1-1
Resource Needs ....................................................................................................................... 1-1
Modeling and Results ............................................................................................................... 1-2
Energy Efficiency and Demand Response............................................................................... 1-3
Preferred Resource Strategy ................................................................................................... 1-4
Clean Energy Goals ................................................................................................................. 1-6
Energy Equity ........................................................................................................................... 1-8
Action Items .............................................................................................................................. 1-8
2. Introduction and Stakeholder Involvement ................................................................ 2-1
IRP Process ............................................................................................................................. 2-1
2021 IRP Outline ...................................................................................................................... 2-4
Idaho Regulatory Requirements .............................................................................................. 2-5
Washington Regulatory Requirements .................................................................................. 2-10
Summary of 2021 IRP Changes from the 2017 and 2020 IRPs ............................................ 2-18
3. Economic & Load Forecast .......................................................................................... 3-1
Economic Characteristics of Avista’s Service Territory ............................................................ 3-1
IRP Long-Run Load Forecast ................................................................................................ 3-12
Monthly Peak Load Forecast Methodology ............................................................................ 3-22
Simulated Extreme Weather Conditions with Historical Weather Data ................................. 3-23
4. Existing Supply Resources .......................................................................................... 4-1
Spokane River Hydroelectric Developments ........................................................................... 4-2
Clark Fork River Hydroelectric Development ........................................................................... 4-3
Total Hydroelectric Generation ................................................................................................ 4-4
Thermal Resources .................................................................................................................. 4-4
Small Avista-Owned Solar ....................................................................................................... 4-7
Power Purchase and Sale Contracts ....................................................................................... 4-7
Customer-Owned Generation ................................................................................................ 4-10
Natural Gas Pipeline Rights ................................................................................................... 4-11
Resource Environmental Requirements and Issues .............................................................. 4-13
Colstrip ................................................................................................................................... 4-18
5. Energy Efficiency .......................................................................................................... 5-1
The Conservation Potential Assessment ................................................................................. 5-2
Energy Efficiency Targets ........................................................................................................ 5-6
Energy Efficiency Related Financial Impacts ........................................................................... 5-9
Integrating Results into Business Planning and Operations .................................................. 5-10
Other Energy Efficiency Analysis ........................................................................................... 5-11
Energy Efficiency Avoided Costs ........................................................................................... 5-13
6. Demand Response ........................................................................................................ 6-1
Demand Response Program Descriptions ............................................................................... 6-5
Demand Response Program Participation ............................................................................... 6-7
Demand Response Potential and Cost Assumptions .............................................................. 6-8
Achievable Potential Estimates ................................................................................................ 6-8
Demand Response Peak Credit ............................................................................................. 6-12
7. Long-Term Position ....................................................................................................... 7-1
Reserve Margins ...................................................................................................................... 7-1
Balancing Loads and Resources ............................................................................................. 7-3
2021 IRP Resource Adequacy Assessment ............................................................................ 7-6
Resource Adequacy Risk Assessment .................................................................................... 7-7
Washington State Renewable Portfolio Standard .................................................................. 7-10
Washington State Clean Energy Transformation Act (CETA) ............................................... 7-11
Avista’s Company-Wide Clean Energy Goal.......................................................................... 7-13
Regional Resource Adequacy ................................................................................................ 7-14
8. Transmission & Distribution Planning ........................................................................ 8-1
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Avista Transmission System .................................................................................................... 8-1
Transmission Planning Requirements and Processes ............................................................ 8-2
System Planning Assessment .................................................................................................. 8-4
Distribution Planning ................................................................................................................ 8-8
Merchant Transmission Rights ............................................................................................... 8-11
9. Supply-Side Resource Options .................................................................................... 9-1
Assumptions ............................................................................................................................. 9-1
Hydro Project Upgrades and Options .................................................................................... 9-22
Thermal Resource Upgrade Options ..................................................................................... 9-25
Intermittent Generation Costs ................................................................................................ 9-25
Sub Hourly Resource and Ancillary Services Benefits .......................................................... 9-26
Resource Peak Credit and ELCC Analysis ............................................................................ 9-27
Other Environmental Considerations ..................................................................................... 9-29 Market Analysis ........................................................................................................... 10-1
Electric Marketplace ............................................................................................................... 10-2
Western Interconnect Loads .................................................................................................. 10-3
Generation Resources ........................................................................................................... 10-6
Generation Operating Characteristics .................................................................................... 10-8
Electric Resource and Emissions Forecast ......................................................................... 10-15
Electric Market Price Forecast ............................................................................................. 10-20
Scenario Analyses ................................................................................................................ 10-25
11. Preferred Resource Strategy ...................................................................................... 11-1
Resource Selection Process .................................................................................................. 11-2
The Preferred Resource Strategy .......................................................................................... 11-4
Avoided Cost ........................................................................................................................ 11-18
12. Portfolio Scenario Analysis ........................................................................................ 12-1
Portfolio Scenarios ................................................................................................................. 12-2
Cost and Rate Comparison .................................................................................................. 12-34
Greenhouse Gas Analysis ................................................................................................... 12-37
Risk Analysis ........................................................................................................................ 12-39
Reliability Analysis ................................................................................................................ 12-42
Market Price Sensitivities ..................................................................................................... 12-42
Social Cost of Carbon Portfolio Optimization ....................................................................... 12-44
Climate Shift Portfolio Optimization ...................................................................................... 12-45
Washington Maximum Customer Benefit Scenario ............................................................. 12-47
Expected Case Portfolio Summary ...................................................................................... 12-50
13. Energy Equity............................................................................................................... 13-1
CETA Requirements .............................................................................................................. 13-2
Community Identification ........................................................................................................ 13-3
Baseline Analysis ................................................................................................................... 13-7
Vulnerable Population Action Plan ....................................................................................... 13-14
14. Action Items ................................................................................................................. 14-1
Summary of the 2017 IRP Action Plan................................................................................... 14-1
2020 IRP Two Year Action Plan ............................................................................................. 14-4
15. Washington Clean Energy Action Plan ..................................................................... 15-1
Energy Efficiency Savings ...................................................................................................... 15-1
Resource Adequacy ............................................................................................................... 15-2
Demand Response and Load Management Programs .......................................................... 15-3
Energy Equity ......................................................................................................................... 15-6

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Table of Figures

Figure 1.1: Load-Resource Balance—Winter Peak Load & Resource Availability ...................... 1-1
Figure 1.2: Average Mid-Columbia Electricity Price Forecast ...................................................... 1-2
Figure 1.3: Stanfield Natural Gas Price Forecast ......................................................................... 1-3
Figure 1.4: Avista’s Annual and Cumulative Energy Efficiency Acquisitions ............................... 1-4
Figure 1.5: Portfolio Scenario Analysis......................................................................................... 1-6
Figure 1.6: Avista’s Clean Energy Acquisition Forecast............................................................... 1-7
Figure 1.7: Avista Greenhouse Gas Emissions Forecast ............................................................ 1-8
Figure 3.1: MSA Population Growth and U.S. Recessions, 1971-2019 ....................................... 3-2
Figure 3.2: Avista and U.S. MSA Population Growth, 2007-2019 ................................................ 3-3
Figure 3.3: MSA Non-Farm Employment Breakdown by Major Sector, 2019 .............................. 3-4
Figure 3.4: Avista and U.S. MSA Non-Farm Employment Growth, 2010-2019 ........................... 3-5
Figure 3.5: MSA Personal Income Breakdown by Major Source, 2019 ....................................... 3-6
Figure 3.6: Avista and U.S. MSA Real Personal Income Growth by Decade, 1970-2019 ........... 3-6
Figure 3.7: Forecasting IP Growth................................................................................................ 3-9
Figure 3.8: Industrial Load and Industrial (IP) Index .................................................................. 3-10
Figure 3.9: Population Growth vs. Customer Growth, 2000-2019 ............................................. 3-11
Figure 3.10: Forecasting Population Growth .............................................................................. 3-12
Figure 3.11: Long-Run Annual Residential Customer Growth ................................................... 3-14
Figure 3.12: Electric Vehicle and Rooftop Solar Load Changes ................................................ 3-16
Figure 3.13: Average Megawatts, High/Low Economic Growth Scenarios ................................ 3-18
Figure 3.14: UPC Growth Forecast Comparison to EIA ............................................................. 3-19
Figure 3.15: Load Growth Comparison to EIA ........................................................................... 3-19
Figure 3.16: Average Megawatts with Climate Scenarios .......................................................... 3-21
Figure 3.17: Load Share Comparison with Climate Scenarios .................................................. 3-21
Figure 3.18: Peak Load Forecast 2021-2045 ............................................................................. 3-25
Figure 3.19: Peak Load Forecast with 1 in 20 High/Low Bounds, 2021-2045 ........................... 3-26
Figure 3.20: Peak Load Forecast with Avista Trended 20-yr MA, 2021-2045 ........................... 3-27
Figure 3.21: Peak Load Forecast with 1-in-20 High/Low Bounds and ....................................... 3-27
Figure 3.22: Peak Load Forecast with 1 in 20 High/Low Bounds and ....................................... 3-28
Figure 4.1: 2020 Avista Capability and Energy Fuel Mix ............................................................. 4-1
Figure 4.2: 2019 Washington State Fuel Mix Disclosure ............................................................. 4-2
Figure 4.3: Avista’s Net Metering Customers ............................................................................. 4-11
Figure 4.4: Avista Firm Natural Gas Pipeline Rights .................................................................. 4-12
Figure 5.1: Historical Conservation Acquisition (system) ............................................................. 5-2
Figure 5.2: Analysis Approach Overview ..................................................................................... 5-3
Figure 5.3: Conservation Potential Assessment - 20-Year Cumulative GWh .............................. 5-6
Figure 5.4: Energy Efficiency Savings by Segment ..................................................................... 5-7
Figure 5.5: Washington Annual Achievable Potential Energy Efficiency (Gigawatt Hours) ......... 5-8
Figure 5.6: Cumulative Energy Efficiency Costs .......................................................................... 5-9
Figure 5.7: Washington Energy Efficiency Avoided Cost ........................................................... 5-14
Figure 5.8: Idaho Energy Efficiency Avoided Cost ..................................................................... 5-14
Figure 6.1: Program Characterization Process ............................................................................ 6-3
Figure 7.1: Stand Alone Northwest Utility vs. Avista’s L&R Methodology .................................... 7-3
Figure 7.2: Winter One-Hour Peak Capacity Load and Resources Balance ............................... 7-4
Figure 7.3: Summer One-Hour Peak Capacity Load and Resources Balance ............................ 7-4
Figure 7.4: Annual Average Energy Load and Resources ........................................................... 7-5
Figure 7.5: State Level Load and Resource Position by State ..................................................... 7-6
Figure 7.6: Avista versus Regional Loads (98th percentile) ........................................................ 7-10
Figure 7.7: Washington State CETA Compliance Position ........................................................ 7-12
Figure 7.8: Avista Clean Energy Goal ........................................................................................ 7-13
Figure 8.1: Avista Transmission System ...................................................................................... 8-1
Figure 8.2: Avista 230 kV Transmission System .......................................................................... 8-2
Figure 8.3: NERC Interconnection Map ....................................................................................... 8-3
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Figure 9.1: Storage Upfront Capital Cost versus Duration ......................................................... 9-11
Figure 9.1: Lithium-ion Capital Cost Forecast ............................................................................ 9-13
Figure 9.2: Wholesale Hydrogen Costs per Kilogram ................................................................ 9-17
Figure 9.3: Historical and Planned Hydro Upgrades .................................................................. 9-23
Figure 9.4: Social Cost of Carbon .............................................................................................. 9-30
Figure 10.1: NERC Interconnection Map ................................................................................... 10-3
Figure 10.2: 24-Year Annual Average Western Interconnect Load Forecast ............................ 10-4
Figure 10.3: Cumulative Resource Retirement Forecast ........................................................... 10-7
Figure 10.4: Western Generation Resource Additions (Nameplate Capacity) ........................... 10-8
Figure 10.5: Henry Hub Natural Gas Price Forecast .................................................................. 10-9
Figure 10.6: Stochastic Stanfield Natural Gas Price Forecast ................................................. 10-11
Figure 10.7: Stanfield Nominal 20-Year Nominal Levelized Price Distribution ........................ 10-11
Figure 10.8: Northwest Expected Energy ................................................................................. 10-13
Figure 10.9: Generation Technology History and Forecast ..................................................... 10-16
Figure 10.10: Northwest Generation Technology History and Forecast .................................. 10-17
Figure 10.11: 2019 Greenhouse Gas Emissions ..................................................................... 10-18
Figure 10.12: Greenhouse Gas Emissions Forecast ............................................................... 10-18
Figure 10.13: Northwest Regional Greenhouse Gas Emissions Intensity ............................... 10-19
Figure 10.14: Northwest Incremental Greenhouse Gas Emissions Intensity Rates ................ 10-20
Figure 10.15: Mid-Columbia Electric Price Forecast Range .................................................... 10-21
Figure 10.16: Winter Average Hourly Electric Prices (December - February) ......................... 10-23
Figure 10.17: Spring Average Hourly Electric Prices (March - June) ....................................... 10-23
Figure 10.18: Summer Average Hourly Electric Prices (July - September) ............................. 10-24
Figure 10.19: Autumn Average Hourly Electric Prices (October - November) ......................... 10-24
Figure 10.20: Change in Hydroelectric Generation .................................................................. 10-26
Figure 10.21: Forecast Change in Monthly Northwest Load Due to Climate Change ............. 10-27
Figure 10.22: Change in Henry Hub Natural Gas Prices ......................................................... 10-28
Figure 10.23: Mid-Columbia Nominal Levelized Prices Scenario Analysis .............................. 10-28
Figure 10.24: Mid-Columbia Annual Electric Price Scenario Analysis ..................................... 10-29
Figure 10.25: 2040 Western Interconnect Generation Forecast .............................................. 10-30
Figure 10.26: Scenario Greenhouse Gas Emissions ............................................................... 10-31
Figure 11.1: Annual PRS Demand Response Capability ........................................................... 11-9
Figure 11.2: Energy Efficiency Annual Forecast ...................................................................... 11-10
Figure 11.3: Energy Efficiency Savings Programs ................................................................... 11-11
Figure 11.4: Revenue Requirement and Rate Forecast by State ............................................ 11-13
Figure 11.5: Percent Change in Resource Related Rates ....................................................... 11-14
Figure 11.6: Annual Clean Energy for the System Sales ......................................................... 11-16
Figure 11.7: Annual Clean Energy for Washington Portion of Sales ....................................... 11-16
Figure 11.8: Annual Clean Energy for Idaho Portion of Sales ................................................. 11-17
Figure 11.9: Greenhouse Gas Emissions ................................................................................ 11-18
Figure 11.10: Total Net Greenhouse Gas Emissions Intensity ................................................ 11-18
Figure 12.1: Resource Adequacy Load Resource Position Changes ...................................... 12-13
Figure 12.2: Natural Gas to Electric Load Relationship ........................................................... 12-15
Figure 12.3: Electrification Scenario #1 Additional Load .......................................................... 12-16
Figure 12.4: Electrification Scenario #1 Monthly Load ............................................................. 12-16
Figure 12.5: Hybrid Scenario Natural Gas to Electric Load Relationship................................. 12-19
Figure 12.6: Electrification Scenario #2 Load Change from Electrification Scenario #1 .......... 12-20
Figure 12.7: High Efficiency Scenario Natural Gas to Electric Load Relationship ................... 12-22
Figure 12.8: Electrification Load Increase Comparison ........................................................... 12-23
Figure 12.9: Washington Portfolio Average Energy Rates ....................................................... 12-35
Figure 12.10: Idaho Portfolio Average Energy Rates ............................................................... 12-36
Figure 12.11: Portfolio Average Energy Levelized Revenue Requirement .............................. 12-37
Figure 12.12: Levelized Greenhouse Gas Emissions .............................................................. 12-38
Figure 12.13: Change in Greenhouse Gas Emissions Compared to Change in Cost ............. 12-39
Figure 12.14: Portfolio’s Standard Deviation versus Portfolio’s Levelized PVRR .................... 12-40
Figure 12.15: Portfolio’s Tail Risk vs Portfolio’s Levelized PVRR ............................................ 12-40
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Figure 12.16: Portfolio PVRR with Risk Analysis ..................................................................... 12-41
Figure 12.17: Climate Shift Land and Resource Position Change ........................................... 12-46
Figure 13.1: Washington Department of Health Disparities Map ............................................... 13-4
Figure 13.2: Vulnerable Population Areas within Avista Service Territory ................................. 13-5
Figure 13.3: Vulnerable Population Areas within Spokane Area ............................................... 13-6
Figure 13.4: Electric Customer Energy Cost versus Income ..................................................... 13-9
Figure 13.5: Electric/Natural Gas Customer Cost versus Income ............................................ 13-10
Figure 13.6: CAIDI Historical Comparison ............................................................................... 13-11
Figure 13.7: CEMI Historical Comparison ................................................................................ 13-11
Figure 13.8: 5-year Average CAIDI Map .................................................................................. 13-12
Figure 13.9: 5-year Average CEMI Map ................................................................................... 13-13
Figure 15.1: Washington 10-year Energy Efficiency Target ....................................................... 15-2

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Table of Tables

Table 1.1: The 2021 Preferred Resource Strategy ...................................................................... 1-5
Table 2.1: TAC Meeting Dates and Agenda Items ....................................................................... 2-2
Table 2.2: External Technical Advisory Committee Participating Organizations ......................... 2-3
Table 2.3: Timing & Plan Horizon ............................................................................................... 2-10
Table 2.4: Load Forecast ............................................................................................................ 2-10
Table 2.5: Demand-Side Resources & DERs ............................................................................ 2-11
Table 2.6: Supply-Side Resources ............................................................................................. 2-12
Table 2.7: Regional Generation & Transmission ........................................................................ 2-12
Table 2.8: Resource Evaluation ................................................................................................. 2-13
Table 2.9: Resource Adequacy Metric Determination & Identification ....................................... 2-13
Table 2.10: Economic, Health, Environmental Burdens and Benefits, and Equity .................... 2-14
Table 2.11: Cases, Scenarios, & Sensitivities ............................................................................ 2-14
Table 2.12: Portfolio Analysis and Preferred Portfolio................................................................ 2-15
Table 2.13: Clean Energy Action Plan ....................................................................................... 2-16
Table 2.14: Avoided Cost ........................................................................................................... 2-17
Table 2.15: Process .................................................................................................................... 2-17
Table 3.1: UPC Models Using Non-Weather Driver Variables ..................................................... 3-9
Table 3.2: Customer Growth Correlations, January 2005 – October 2020 ................................ 3-11
Table 3.3: High/Low Economic Growth Scenarios (2021-2045) ................................................ 3-18
Table 3.4: Load Growth for High/Low Economic Growth Scenarios (2021-2045) ..................... 3-18
Table 3.5: Load Growth for Climate Scenarios (2026-2045) ...................................................... 3-20
Table 3.6: Forecasted Winter and Summer Peak Growth, 2021-2045 ...................................... 3-25
Table 3.7: Forecasted Winter and Summer Peak ...................................................................... 3-26
Table 3.8: Energy and Peak Forecasts ...................................................................................... 3-29
Table 4.1: Avista-Owned Hydroelectric Resources ...................................................................... 4-4
Table 4.2: Avista-Owned Thermal Resources .............................................................................. 4-5
Table 4.3: Avista-Owned Thermal Resource Capability .............................................................. 4-5
Table 4.4: Avista-Owned Solar Resource Capability ................................................................... 4-7
Table 4.5: Mid-Columbia Capacity and Energy Contracts ........................................................... 4-8
Table 4.6: PURPA Agreements .................................................................................................... 4-9
Table 4.7: Other Contractual Rights and Obligations ................................................................. 4-10
Table 4.8: Top Five Historical Peak Natural Gas Usage (Dekatherms) ..................................... 4-12
Table 4.9: Avista Owned and Controlled PM Emissions ............................................................ 4-16
Table 5.1: Cumulative Potential Savings (Across All Sectors for Selected Years) ...................... 5-5
Table 5.2: Biennial Conservation Target for Washington Energy Efficiency ................................ 5-8
Table 5.3: Annual Achievable Potential Energy Efficiency (Megawatt Hours) ............................. 5-8
Table 5.4: Transmission and Distribution Benefits (System) ..................................................... 5-12
Table 6.1: Demand Response Program Options by Market Segment ......................................... 6-4
Table 6.2: DR Program Steady-State Participation Rates (% of eligible customers) ................... 6-7
Table 6.3: DR Program Costs and Potential – Winter TOU Opt-In ............................................ 6-10
Table 6.4: DR Program Costs and Potential – Summer TOU Opt-In ......................................... 6-12
Table 7.1: LOLP Reliability Study Results without New Resources ............................................. 7-7
Table 7.2: Washington State EIA Compliance Position Prior to REC Banking (aMW) .............. 7-11
Table 7.3: NPCC 2024 Resource Adequacy Analysis ............................................................... 7-15
Table 8.1: 2021 IRP Generation Study Transmission Costs ........................................................ 8-6
Table 8.2: Third-Party Large Generation Interconnection Requests ............................................ 8-7
Table 8.3: Merchant Transmission Rights .................................................................................. 8-11
Table 9.1: Natural Gas-Fired Plant Levelized Costs .................................................................... 9-5
Table 9.2: Natural Gas-Fired Plant Cost and Operational Characteristics................................... 9-6
Table 9.3: Levelized Wind Prices ($/MWh) .................................................................................. 9-8
Table 9.4: Levelized Solar Prices ................................................................................................. 9-9
Table 9.5: Storage Cost w Solar System ($/kW-month)............................................................. 9-10
Table 9.6: Pumped Hydro Company-Owned Options ................................................................ 9-12
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Table 9.7: Lithium-ion Levelized Cost $/kW ............................................................................... 9-14
Table 9.8: Flow Battery Levelized Cost $/kWh of Capacity ....................................................... 9-15
Table 9.9: Hydrogen Storage, Fuel Cell and Turbine Levelized Cost $/kWh ............................. 9-18
Table 9.10: Hydroelectric Upgrade Options ............................................................................... 9-24
Table 9.11: Ancillary Services & Sub-hourly Value Estimates (2020 dollars) ............................ 9-27
Table 9.12: Peak Credit or Equivalent Load Carrying Capability Credit .................................... 9-28
Table 10.1: AURORA Zones ...................................................................................................... 10-3
Table 10.2: January through June Load Area Correlations ....................................................... 10-5
Table 10.3: July through December Load Area Correlations ..................................................... 10-5
Table 10.4: Area Load Coefficient of Determination (Standard Deviation/Mean) ...................... 10-6
Table 10.5: Area Load Coefficient of Determination (Standard Deviation/Mean) ...................... 10-6
Table 10.6: Natural Gas Price Basin Differentials from Henry Hub ......................................... 10-10
Table 10.7: Nominal Levelized Flat Mid-Columbia Electric Price Forecast.............................. 10-21
Table 10.8: Annual Average Mid-Columbia Electric Prices ($/MWh) ....................................... 10-22
Table 10.9: Change in 2040 Regional Generation ................................................................... 10-30
Table 11.1: 2021 Preferred Resource Strategy (2022-2031) ..................................................... 11-6
Table 11.2: 2021 Preferred Resource Strategy (2032-2041) ..................................................... 11-7
Table 11.3: 2021 Preferred Resource Strategy (2042-2045) ..................................................... 11-8
Table 11.4: PRS Demand Response Programs ......................................................................... 11-9
Table 11.5: Reliability Metrics ................................................................................................... 11-12
Table 11.6: 2022-2024 Cost Cap Analysis (millions $) ............................................................ 11-15
Table 11.7: New Resource Avoided Costs ............................................................................... 11-20
Table 12.1: Portfolio #1- Preferred Resource Strategy Resource Selection .............................. 12-2
Table 12.2: Portfolio #2- Baseline Portfolio #1 Resource Selection ........................................... 12-3
Table 12.3: Portfolio #3- Baseline Portfolio #2 Resource Selection ........................................... 12-4
Table 12.4: Portfolio #4- Baseline Portfolio #3 Resource Selection ........................................... 12-5
Table 12.5: Portfolio #5- Clean Resource Plan (2027) Resource Selection .............................. 12-6
Table 12.6: Portfolio #6- Clean Resource Plan (2045) Resource Selection .............................. 12-8
Table 12.7: Portfolio #6b- Clean Resource Plan (2045) Resource Selection without Colstrip .. 12-9
Table 12.8: Portfolio #7- Idaho Social Cost of Carbon Portfolio Resource Selection .............. 12-10
Table 12.9: Portfolio #8 Low Load Forecast Resource Selection ............................................ 12-11
Table 12.10: Portfolio #9 High Load Forecast Resource Selection ......................................... 12-12
Table 12.11: Portfolio #10: Resource Adequacy Program Resource Selection ...................... 12-14
Table 12.12: Portfolio #11- Electrification Portfolio #1 Resource Selection ............................. 12-18
Table 12.13: Portfolio #12- Electrification Scenario #2 Resource Selection ............................ 12-21
Table 12.14: Portfolio #13- Electrification Scenario #3 Resource Selection ............................ 12-24
Table 12.15: Portfolio #14- 2x Social Cost of Carbon Resource Selection .............................. 12-25
Table 12.16: Portfolio #15- Colstrip Exit in 2025 Resource Selection ...................................... 12-26
Table 12.17: Portfolio #16- Colstrip Exit in 2035 Resource Selection ...................................... 12-27
Table 12.18: Portfolio #17- Colstrip Exit in 2045 Resource Selection ...................................... 12-29
Table 12.19: Portfolio #18- Clean Energy Delivered Each Hour Resource Selection ............. 12-30
Table 12.20: Portfolio #19- SCC on Purchases/Sales Resource Selection ............................. 12-31
Table 12.21: Portfolio #20- Average Market Emissions Intensity for Energy Efficiency Resource
Selection .......................................................................................................................... 12-33
Table 12.22: Portfolio Costs and Rates .................................................................................... 12-34
Table 12.23: Portfolio Scenario’s Reliability Analysis ............................................................... 12-42
Table 12.24: Change in Cost (PVRR) Compared to Expected Case ....................................... 12-43
Table 12.25: Levelized Greenhouse Gas Emissions vs. Expected Case ................................ 12-44
Table 12.26: Optimized Social Cost of Carbon Future Portfolio .............................................. 12-45
Table 12.27: Optimized Social Cost of Carbon Future Portfolio .............................................. 12-47
Table 12.28: Customer Benefits ............................................................................................... 12-49
Table 12.29: Optimized Social Cost of Carbon Future Portfolio .............................................. 12-50
Table 12.30: 2022-2045 Portfolio Selection Summary ............................................................. 12-51
Table 13.1: Percent of Service Territory Area Above the DOH score ........................................ 13-7
Table 13.2: Electric Energy Use and Energy Burden Comparison ............................................ 13-7
Table 13.3: Electric & Natural Gas Energy Use and Energy Burden Comparison .................... 13-8
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Avista Corp 2021 Electric IRP

viii
Table 13.4: Existing Facilities within Identified Areas............................................................... 13-14
Table 15.1: Washington Annual Capacity by Resource Type .................................................... 15-2

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Avista Corp 2021 Electric IRP

ix
Appendix Table of Contents

Appendix A – 2021 IRP Technical Advisory Committee Presentations & Meeting
Notes

Appendix B – 2021 Electric IRP Work Plan

Appendix C – Public Participation Comments

Appendix D – Confidential Historical Generation Operation Data

Appendix E – AEG Conservation & Demand Response Potential Assessment

Appendix F – Avoided Cost Calculations

Appendix G – Transmission 10- year plan and System Assessment

Appendix H – New Resource Table for Transmission

Appendix I – Publicly Available Inputs and Models

Appendix J – Confidential Inputs and Models

Appendix K – Load Forecast Supplement

Page
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Chapter 1: Executive Summary
Avista Corp 2021 Electric IRP 1-1
1. Executive Summary

The 2021 Electric Integrated Resource Plan (IRP) shapes Avista’s resource strategy and
planned procurements for the next 24 years. It provides a snapshot of existing resources
and Avista’s load forecast. The plan evaluates supply and demand-side resource options
with multiple resource selection strategies over expected and possible future conditions
to determine an optimal resource strategy to serve customers. The Preferred Resource
Strategy (PRS) relies on modeling methods to balance cost, reliability, rate volatility as
well as environmental goals and mandates. Avista’s management and Technical Advisory
Committee (TAC) guide the IRP development through input and feedback on modeling
and planning assumptions while providing the public with information on future energy
requirements. TAC members include customers, Commission staff, consumer advocates,
academics, environmental groups, utility peers, government agencies, independent
power producers and other interested parties.

Resource Needs
Avista expects its highest peak load during winter cold snaps. Avista’s peak planning
methodology considers operating reserves, regulation, load following, wind integration
and resource adequacy requirements. The Company has adequate resources and energy
efficiency programs to meet both summer and winter peak load requirements through
December 2025. Figure 1.1 shows Avista’s annual resource position through 2045.
Chapter 7 – Long-Term Position details Avista’s projected resource needs. Load growth
and the loss of Colstrip1, Lancaster, Northeast, Boulder Park and expiring hydro contracts
drive Avista’s resource deficits.

Figure 1.1: Load-Resource Balance—Winter Peak Load & Resource Availability

1 This IRP assumes Colstrip no longer serves Washington customers after 2025, while portfolio modeling
determines the economic end life for Idaho’s portion of the plant. For planning purposes, Avista assumes
the plant exits in 2025 as shown in Figure 1.1.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Chapter 1: Executive Summary
Avista Corp 2021 Electric IRP 1-2
Modeling and Results
Avista uses a multistep process to develop its PRS, beginning with a market analysis
using the Aurora software by Energy Exemplar to identify and quantify the fundamental
changes expected in the Western Interconnect between 2022 and 2045. The model uses
the regional generation resources, load estimates and transmission links described in
Chapter 10. The model adds new resources throughout the western region as loads
transform to serve new uses and existing resources retire. Monte Carlo-style analyses
vary hydro and wind generation, weather, forced outages and natural gas price data over
500 iterations of potential future market conditions to develop a forecast of wholesale Mid-
Columbia electricity market prices through 2045. This forecast is used to value Avista’s
resource alternatives.

Figure 1.2 shows the 2021 IRP Mid-Columbia electricity price forecast for the Expected
Case, including the range of prices from the 500 Monte Carlo iterations. The levelized
price is $27.13 per MWh in nominal dollars over the 2022-2045 timeframe.

Figure 1.2: Average Mid-Columbia Electricity Price Forecast

Electricity and natural gas prices are highly correlated because natural gas fuels marginal
generation in the Northwest during most of the year. Figure 1.3 presents nominal
Expected Case natural gas prices at the Stanfield trading hub, located in northeastern
Oregon, as well as the forecast range from the 500 Monte Carlo iterations performed for
the Expected Case. The average natural gas price is $3.45 per dekatherm (Dth) over the
next 24 years. See Chapter 10 – Market Analysis for natural gas and electricity price
forecasts.

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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Chapter 1: Executive Summary
Avista Corp 2021 Electric IRP 1-3
Figure 1.3: Stanfield Natural Gas Price Forecast

Energy Efficiency and Demand Response
Avista commissioned a Conservation Potential Assessment (CPA) and a Demand
Response potential study to estimate the potential for those applications in its service
area. These studies provided Avista with approximately 7,000 potential energy efficiency
measures and 16 Demand Response programs. Avista’s commitment to energy efficiency
is evident with a 14.5 percent reduction in average load since 1978 due to these efforts.
Figure 1.4 illustrates the historical efficiency acquisitions as blue bars and the dashed line
shows the amount of energy efficiency Avista estimates to remain on the system today.2
Going forward, Avista expects energy efficiency to serve 68 percent of future load growth.
See Chapter 5 – Energy Efficiency for more information. Demand Response programs
will be integral to serving peak load using a variety of cost-effective programs and rate
redesigns. See Chapter 6 – Demand Response for more information.

2 Cumulative savings are lower than the summation of annual program savings due to the estimated 18-
year average measure life.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Chapter 1: Executive Summary
Avista Corp 2021 Electric IRP 1-4
Figure 1.4: Avista’s Annual and Cumulative Energy Efficiency Acquisitions

Preferred Resource Strategy
The PRS results from careful consideration and input by Avista’s management, the TAC,
and information gathered and analyzed through the IRP process. The PRS meets future
reliability and clean energy requirements with upgrades at existing generation facilities
(thermal and hydro), energy efficiency, natural gas peakers, energy storage, contracts,
new renewable resources and demand response, as shown in Table 1.1. These resource
selections are based on an economic decision-making process using both societal and
resource cost estimates. Actual resource acquisition will occur through a competitive
Request for Proposal (RFP) process where submitted resources will be evaluated to meet
the Company’s resource needs, such as Avista’s 2020 Renewable RFP. This RFP may
modify this plan if actual resource acquisition occurs and provides substitutes for planned
resource needs.

The 2021 PRS is the lowest-reasonable cost plan to meet both reliability and
environmental requirements given the resource inputs and need assessment. Major
changes from the 2020 IRP include the return of new natural gas-fired peakers as long
term energy storage is not cost effective as initially estimated in the 2020 IRP for the
Company’s initial 2026 capacity need. The plan also lowers the estimated demand
response, wind acquisition and hydro upgrade quantities.

Each new supply- and demand-side resource option is valued against the Mid-Columbia
electricity market forecast to identify its future energy value, as well as its inherent risk
measured by year-to-year portfolio power cost volatility. These values, and associated
capital and fixed operation and maintenance (O&M) costs, form the input into Avista’s
Preferred Resource Strategy Model (PRiSM). PRiSM assists Avista by mathematically
determining optimal mixes of new resources. The resource plan may change over time
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Chapter 1: Executive Summary
Avista Corp 2021 Electric IRP 1-5
depending on whether projects identified in the IRP remain cost competitive and available
at the time of need.

Table 1.1: The 2021 Preferred Resource Strategy

Resource Type Year State Capability
Colstrip 2021 WA/ID (222)
Montana wind 2023 WA 100
Montana wind 2024 WA 100
Lancaster 2026 WA/ID (257)
Kettle Falls Upgrade 2026 WA/ID 12
Post Falls Upgrade 2026 WA/ID 8
Natural Gas Peaker 2027 ID 85
Natural Gas Peaker 2027 WA/ID 126
Montana wind 2028 WA 100
NW Hydro Slice 2031 WA 75
Rathdrum CT Upgrade 2035 WA/ID 5
Northeast 2035 WA/ID (54)
Natural Gas Peaker 2036 WA/ID 87
Solar w/ storage (4 hours) 2038 WA/ID 100
4-hr Storage for Solar 2038 WA/ID 50
Boulder Park 2040 WA/ID (25)
Natural Gas Peaker 2041 ID 36
Montana wind 2041 WA 100
Solar w/ storage (4 hours) 2042-2043 WA 239
4-hr Storage for Solar 2042-2043 WA 119
Liquid Air Storage 2044 WA 12
Liquid Air Storage 2045 ID 10
Solar w/ storage (4 hours) 2045 WA 149
4-hr Storage for Solar 2045 WA 75

Supply-side resource net total (MW) 1,032
Supply-side resource total additions (MW) 1,589
Demand Response 2045 capability (MW) 71
Cumulative energy efficiency (aMW) 121
Cumulative summer peak savings (MW) 111
Cumulative winter peak savings (MW) 116

The PRS provides customers with the lowest-reasonable cost portfolio, minimizing future
costs and risks within actual and expected environmental constraints. Similar to finding
an optimal mix of risk and return in an investment portfolio, a preferred resource strategy
is a balance between cost and risk. As potential returns increase, so do risks. Conversely,
reducing risk generally increases overall cost. Figure 1.5 presents the change in cost and
risk from the many portfolio scenarios compared to the PRS. Lower power cost variability
comes from investments in more expensive, but less risky, resources such as wind and
hydroelectric upgrades, with risk measured by lower cost volatility.

Chapter 12 – Portfolio Scenario Analysis includes scenarios and market sensitives
illustrating how the PRS could change under different conditions and alternate market
futures. It also evaluates the impacts of varying load growth, resource availability, market
dynamics and greenhouse gas policies.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Chapter 1: Executive Summary
Avista Corp 2021 Electric IRP 1-6
Figure 1.5: Portfolio Scenario Analysis

Clean Energy Goals
Acquiring an additional 375 MW (by 2031) of new clean energy resources along with
upgrades to its hydroelectric and biomass facilities will position Avista to meet or exceed
Washington’s clean energy requirements. The PRS meets nearly 78 percent of Avista’s
corporate clean energy goal to provide customers with 100 percent net clean energy by
2027 at competitive prices. Figure 1.6 compares Avista’s total energy retail sales (Idaho
and Washington) and the annual average clean energy resources serving customers.
Avista’s plan also exceeds goals of Washington’s Energy Independence Act (EIA), relying
on output from the Palouse and Rattlesnake Flat Wind contracts, generation from the
Kettle Falls biomass facility and upgrades to the Clark Fork and Spokane River
hydroelectric developments.

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Strategy
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11- Electrification 1
12- Electrification 213- Electrification 3
14- 2x SCC
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EE SCC
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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Chapter 1: Executive Summary
Avista Corp 2021 Electric IRP 1-7
Figure 1.6: Avista’s Clean Energy Acquisition Forecast

The shift to clean energy will reduce Avista’s greenhouse gas footprint significantly.
Figure 1.7 shows how emissions will decrease from 2019 levels by 74 percent in 2030 or
2.2 million metric tons. Since the exact removal date of Colstrip from the Avista resource
portfolio is not known, Figure 1.7 shows emissions including Colstrip through 2025
(dashed line) and with the removal of Colstrip starting in 2022 for comparison purposes.
When accounting for Avista’s contributions through incentives and programs to shift
transportation fuel from petroleum to electricity, regional greenhouse gas reductions may
be greater than those from the removal of coal- and natural gas-fired generation.

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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Chapter 1: Executive Summary
Avista Corp 2021 Electric IRP 1-8
Figure 1.7: Avista Greenhouse Gas Emissions Forecast

Energy Equity
Washington’s Clean Energy Transformation Act (CETA) expands Avista’s commitment to
bring affordable energy to customers particularly those in Highly Impacted Communities
and vulnerable populations. Avista began a process to identify vulnerable populations
within its service territory to better understand the difference in energy burden and
reliability for these populations. The Company is committed to finalizing a methodology
and developing programs to increase energy affordability of these populations in the next
IRP and Clean Energy Implementation Plan. This process will begin with the development
of an Equity Advisory Group (EAG) described in Chapter 13 and a low-income energy
efficiency pilot program.

Action Items
The 2021 Action Items chapter provides a progress report on Action Items from the 2020
and 2017 IRPs, and outlines activities Avista intends to perform between the publication
of this report and the next IRP. Action Items reflect input from staff at both state
Commissions, Avista’s management team and the TAC. Refer to Chapter 14 – Action
Items for details about each of these categories.

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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Chapter 2: Introduction and Stakeholder Involvement
Avista Corp 2021 Electric IRP 2-1
2. Introduction and Stakeholder Involvement

Avista submits an Integrated Resource Plan (IRP) to the Idaho and Washington public
utility commissions biennially.1 Including its first plan in 1989, the 2021 IRP is Avista’s
seventeenth plan. The IRP identifies and describes a Preferred Resource Strategy to
meet load growth, resource deficits and environmental requirements while balancing cost
and risk measures.

Avista is statutorily obligated to provide safe and reliable electricity service to its
customers at rates, terms and conditions that are fair, just, reasonable and sufficient.
Avista assesses different resource acquisition strategies and business plans to acquire a
mix of resources meeting resource adequacy requirements to maintain reliability while
optimizing the value of its current portfolio. The IRP is a resource evaluation tool rather
than a plan for acquiring specific assets. Actual resource acquisitions generally occur
through competitive bidding processes and can result in different types or sizes of
resource selections than previously indicated by the IRP process because acquisitions
are based on the bids received.

IRP Process
This IRP process follows up on the 2020 IRP filed in Idaho by incorporating new
requirements and a modified schedule to comply with CETA legislation in Washington.
The process is normally completed every two years but was shortened for this IRP cycle.
In March 2019, Avista requested both Washington and Idaho approvals to delay the IRP
filing by six months, effectively creating the 2020 IRP cycle. Ultimately the 2020 IRP was
filed in Idaho, but it was only considered a Progress Report by Washington. This IRP
filing, given the shortened schedule, is the first plan in the new process schedule under
CETA. Avista intends to file the next IRP in Idaho and Washington2 by January 1, 2023
unless a new date is required by either state commission.

The 2021 IRP is developed and written with the aid of a public process. Avista actively
seeks input from many constituents through its Technical Advisory Committee (TAC)
meetings. The TAC is a mix of over 100 external participants, including staff from the
Idaho and Washington commissions, customers, academics, environmental
organizations, government agencies, consultants, utilities and other interested parties
who want to engage in the planning process. Avista distributed a draft of its work plan
prior to submitting the final work plan on April 1, 2020. This shortened IRP process
included five full meetings, two updates and one modeling workshop beginning with its
first meeting on June 18, 2020. A public meeting to seek more customer level input was
also held on February 24, 2021. Each TAC meeting covered different IRP activities. TAC
members provided contributions to and assessed modeling assumptions, modeling
processes and results of Avista studies. Table 2.1 lists TAC meeting dates and agenda
items covered in each meeting.

1 Washington IRP requirements are in WAC 480-100-238 Integrated Resource Planning. Idaho IRP
requirements are in Case No. U-1500-165, Order No. 22299 and Case No. GNR-E-93-3, Order No. 25260.
2 Washington does not require the next full IRP until 2025 and the 2023 filing is a biennial IRP update.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Chapter 2: Introduction and Stakeholder Involvement
Avista Corp 2021 Electric IRP 2-2
Appendix A, available on and Avista’s website3, includes the agendas, presentations and
meeting notes from the 2021 IRP TAC meetings. The website also contains all of the past
IRPs and TAC meeting presentations back to 1989. The final work plan, which
incorporates changes in the schedule, is in Appendix B.

Table 2.1: TAC Meeting Dates and Agenda Items

Meeting Date Agenda Items
TAC 1 – June 18, 2020  TAC Meeting Expectations & IRP Process Review
 Review of 2020 IRP Idaho acknowledgement
 Update on CETA rulemaking process
 Modeling process and assumptions overview
including Aurora, ARAM, ADSS and PRiSM
 Generation options (cost, assumptions, ELCC)
 Highly impacted community discussion (WA-CETA)
TAC 2 – August 6, 2020  Demand and economic forecast
 Conservation Potential Assessment (AEG)
 Demand Response Potential Assessment (AEG)
 Natural gas market overview and price forecast
 Regional energy policy update
 Gas/Electric coordinated studies
 Highly impacted community proposals
Load Forecast – August 18, 2020 
TAC 3 – September 29, 2020  IRP transmission planning studies
 Distribution planning within the IRP
 IRP Transmission Planning Studies
 Discuss market and portfolio scenarios
 Existing resource overview
 Electric market forecast and scenarios
TAC 4 – November 17, 2020  Final resource needs assessment and resource
adequacy
 Ancillary services and intermittent generation
analysis
 Review draft resource plans for each state and
PRiSM Workshop – December 4, 2020 
Scenario Review- December 16, 2020  Draft PRS
 Portfolio Scenario and Sensitivity Results
TAC 5 – January 21, 2021  Review draft IRP
 Final state resource plans and scenarios
 Draft Clean Energy Implementation Plan discussion
 2021 IRP Action Items
 Initial comments from TAC participants
 Overview of ARAM model
Public Meeting – February 24, 2021  Overview of the 2021 IRP and public discussion
 Customer Q&A sessions

3 https://www.myavista.com/about-us/integrated-resource-planning
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Chapter 2: Introduction and Stakeholder Involvement
Avista Corp 2021 Electric IRP 2-3
Avista greatly appreciates the valuable contributions of its TAC members and wishes to
acknowledge and thank the organizations and members who participated in this IRP.
Table 2.2 lists organizations participating in the 2021 IRP TAC process.

Table 2.2: External Technical Advisory Committee Participating Organizations

Organization
4Sight Energy Group National Grid
350.Org Spokane New Sun Energy
AEG NW Energy Coalition
Biomethane, LLC Northwest Power and Conservation Council
Bonneville Power Administration Northwest Renewables
Building Industry Association of Washington Pacific Northwest Utilities Conference
Inland Empire Paper Washington State Department of Community,
Inland Power & Light Washington State Office of the Attorney
Innovari Washington State Department of Enterprise
Kiemle Hagood Washington Utilities and Transportation

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Chapter 2: Introduction and Stakeholder Involvement
Avista Corp 2021 Electric IRP 2-4
Future Public Involvement
Avista actively solicits input from interested parties to enhance its IRP process and
continues to expand its TAC membership and diversity while maintaining the TAC
meetings as an open public process. Anyone who would like to be added to the TAC,
please email [e-mail] for more information.

2021 IRP Outline
The 2021 IRP consists of 15 chapters including the Executive Summary and this
introduction. A series of technical appendices supplement this report.

Chapter 1: Executive Summary
This chapter summarizes the overall results and highlights of the 2021 IRP.

Chapter 2: Introduction and Stakeholder Involvement
This chapter introduces the IRP and details public participation and involvement in the
IRP process.

Chapter 3: Economic and Load Forecast
This chapter covers regional economic conditions, Avista’s energy and peak load
forecasts and load forecast scenarios.

Chapter 4: Existing Supply Resources
This chapter provides an overview of Avista-owned generating resources and its
contractual resources and obligations and environmental regulations.

Chapter 5: Energy Efficiency
This chapter discusses Avista energy efficiency programs. It provides an overview of the
conservation potential assessment and summarizes energy efficiency modeling results.

Chapter 6: Demand Response
This chapter discusses the demand response potential study and an overview of demand
response pilot programs.

Chapter 7: Long-Term Position
This chapter reviews Avista reliability planning and reserve margins, resource
requirements and provides an assessment of its reserves and resource flexibility.

Chapter 8: Transmission & Distribution Planning
This chapter discusses Avista distribution and transmission systems, as well as regional
transmission planning issues. It includes details on transmission cost studies used in IRP
modeling and summarizes the Company’s 10-year Transmission Plan. The chapter
concludes with a discussion of distribution planning; including storage benefits to the
distribution system.

Chapter 9: Supply-Side Resource Options
This chapter covers the cost and operating characteristics of supply side resource options
modeled for the IRP.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Avista Corp 2021 Electric IRP 2-5
Chapter 10: Market Analysis
This chapter details Avista IRP modeling and its analyses of the wholesale market.

Chapter 11: Preferred Resource Strategy
This chapter details the resource selection process used to develop the 2021 PRS and
resulting avoided costs.

Chapter 12: Portfolio Scenarios
This chapter presents alternative resource portfolios and shows how each scenario
performs under different energy market conditions.

Chapter 13: Energy Equity
This chapter discusses the vulnerable population and highly impacted communities
relative to Clean Energy Transformation Act (CETA).

Chapter 14: Action Plan
This chapter discusses progress made on Action Items in the 2020 IRP. It details the
areas Avista will focus on between publication of this plan and the 2023 IRP.

Chapter 15: Clean Energy Action Plan
This chapter discusses action items for compliance with Washington State’s CETA
between publication of this plan and the 2023 IRP.

Idaho Regulatory Requirements
The IRP process for Idaho has several requirements documented in IPUC Orders Nos.
22299 and 25260. Order 22299 dates back to 1989; this order outlines the requirement
for the utility to file a “Resource Management Report”. This report recognize[s] the
managerial aspects of owning and maintaining existing resources as well as procuring
new resources and avoiding/reducing load. [The Commission’s] desire is the report on
the utility’s planning status, not a requirement to implement new planning efforts
according to some bureaucratic dictum. We realize that integrated resource planning is
an ongoing, changing process. Thus, we consider the RMR required herein to be similar
to an accounting balance sheet, i.e., a "freeze-frame" look at a utility's fluid process.

The report should discuss any flexibilities and analyses considered during comprehensive
resource planning such as:

1. Examination of load forecast uncertainties
2. Effects of known or potential changes to existing resources
3. Consideration of demand- and supply-side resource options
4. Contingencies for upgrading, optioning and acquiring resources at optimum times
(considering cost, availability, lead-time, reliability, risk, etc.) as future events
unfold.

Avista outlines the order’s requirements below for ease of readability for each of the
Commission’s requirements.

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Existing Resource Stack
Identification of all resources by category below4; including the utility shall provide a copy
of the utility's most recent U.S. Department of Energy Form EIA-714 submittal and the
following specific data, as defined by the NERC, ought to be included as an appendix5:

a) Hydroelectric;
i. Rated capacity by unit;
ii. Equivalent Availability Factor by month for most recent 5 years;
iii. Equivalent Forced Outage Rate by month for most recent 5 years; and
iv. FERC license expiration date.
b) Coal-fired;
i. Rated Capacity by unit;
ii. Date first put into service;
iii. Design plant life (including life extending upgrades, if any);
iv. Equivalent Availability Factor by month for most recent 5 years; and
v. Equivalent Forced Outage Rate by month for most recent 5 years.
c) Oil or Gas fired;
i. Rated Capacity by unit;
ii. Date first put into service;
iii. Design plant life (including life extending upgrades, if any);
iv. Equivalent Availability Factor by month for most recent 5 years; and
v. Equivalent Forced Outage Rate by month for most recent 5 years.
d) PURPA Hydroelectric;
i. Contractual rated capacity;
ii. Five-year historic hours connected to system, by month (if known);
iii. Five-year historic generation (kWh), by month;
iv. Level of dispatchability, if any; and
v. Contract expiration date.
e) PURPA Thermal;
i. Contractual rated capacity;
ii. Five-year historic hours connected to system, by month (if known);
iii. Five-year historic generation (kWh), by month;
iv. Level of dispatchability, if any; and
v. Contract expiration date.
f) Economy Exchanges;
I. For contract purchases & exchanges, key contract terms and conditions
relating to capacity, energy, availability, price, and longevity.
II. For economy purchases and exchanges, 5-year historical monthly average
capacity, energy, and prices.
g) Economy Purchases;
I. For contract purchases & exchanges, key contract terms and conditions
relating to capacity, energy, availability, price, and longevity.
II. For economy purchases and exchanges, 5-year historical monthly average
capacity, energy, and prices.
h) Contract Purchases;

4 Resources less than three megawatts should be grouped as a single resource in the appropriate category.
5 FERC Form 714 can be on-line at https://www.ferc.gov/docs-filing/forms/form-714/data.asp
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Avista Corp 2021 Electric IRP 2-7
I. For contract purchases & exchanges, key contract terms and conditions
relating to capacity, energy, availability, price, and longevity.
II. For economy purchases and exchanges, 5-year historical monthly average
capacity, energy, and prices.
i) Transmission Resources; and
I. Information useful for estimating the power supply benefits and limitations
appurtenant to the resources in question.
j) Other.
I. Information useful for estimating the power supply benefits and limitations
appurtenant to the resources in question.

Load Forecast
Each RMR should discuss expected 20-year load growth scenarios for retail markets and
for the federal wholesale market including "requirements" customers, firm sales, and
economy (spot) sales. For each appropriate market, the discussion should:
a) identify the most recent monthly peak demand and average energy consumption
(where appropriate by customer class), both firm and interruptible;
b) identify the most probable average annual demand and energy growth rates by
month and, where appropriate, by customer class over at least the next three years
and discuss the years following in more general terms;
c) discuss the level of uncertainty in the forecast, including identification of the
maximum credible deviations from the expected average growth rates; and
d) identify assumptions, methodologies, data bases, models, reports, etc. used to
reach load forecast conclusions.

This section of the report is to be a short synopsis of the utility's present load condition,
expectations and level of confidence. Supporting information does not need to be
included but should be cited and made available upon request.

Additional Resource Menu
This section should consist of the utility's plan for meeting all potential jurisdictional load
over the 20-year planning period. The discussion should include references to expected
costs, reliability and risks inherent in the range of credible future scenarios.
 An ideal way to handle this section could be to describe the most probable 20-year
scenario followed by comparative descriptions of scenarios showing potential
variations in expected load and supply conditions and the utility's expected
responses thereto. Enough scenarios should be presented to give a clear
understanding of the utility's expected responses over the full range of possible
future conditions.
 The guidance provided above is intended to ensure maximum flexibility to utilities
in presenting their resource plans. Ideally, each utility will use several scenarios to
demonstrate potential maximum, minimum and intermediate levels of new
resource requirements and the expected means of fulfilling those requirements.
For example,
o A credible scenario requiring maximum new resources might be regional
load growth exceeding 3% per year combined with catastrophic destruction
(earthquake, fire, flood, etc.) of a utility's largest resource (i.e., Bridger coal
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Avista Corp 2021 Electric IRP 2-8
plant for IPCo and PP&L, Hunter coal plant for UP&L and Noxon hydro plant
for WWP).
o A credible scenario causing reduced utilization of existing resources might
be regional stagflation combined with loss of a major industry within a
utility's service territory. Analyses of intermediate scenarios would also be
useful.
 To demonstrate the risks associated with various proposed responses, certain
types of information should be supplied to describe each method of meeting load.
For example,
o If new hydroelectric generating plants are proposed, the lead time required
to receive FERC licensing and the risk of license denial should be
discussed.
o If new thermal generating plants are proposed, the size, potential for unused
capacity, risks of cost escalation and fuel security should be discussed and
compared to other types of plants.
o If off-system purchases are proposed, specific supply sources should be
identified, regional resource reserve margin should be discussed with
supporting documentation identified, potential transmission constraints
and/or additions should be discussed, and all associated costs should be
estimated.
o If conservation or demand side resources are proposed, they should be
identified by customer class and measure, including documentation of
availability, potential market penetration and cost.
 Because existing hydroelectric plants could be lost to competing companies if
FERC relicensing requirements are not aggressively pursued, relicensing
alternatives require special consideration. For example,
o If hydroelectric plant relicensing upgrades are proposed, their costs should
be presented both as a function of increased plant output and of total plant
output to recognize the potential of losing the entire site.
o Costs of upgrades not required for relicensing should be so identified and
compared only to actual increased capacity/energy availability at the unit,
line, substation, distribution system, or other affected plant. Increased
maintenance costs, instrumentation, monitoring, diagnostics, and capital
investments to improve or maintain availability should be quantified.
 Because PURPA projects are not under the utility's control, they also require
special consideration. Each utility must choose its own way of estimating future
PURPA supplies. The basis for estimates of PURPA generation should be clearly
described.

Other provisions from Order 22299
 Because the RMR is expected to be a report of a utility's plans, and because utilities
are being given broad discretion in choosing their reporting format, Least Cost Plans
or Integrated Resource Plans submitted to other jurisdictions should be applicable in
Idaho.
o Utilities should use discretion and judgement to determine if reports
submitted to other jurisdictions provide such emphasis, if adding an
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appendix would supply such emphasis, or if a separate report should be
prepared for Idaho.
o The project manager responsible for the content and quality of the RMR
shall be clearly identified therein and a resume of her/his qualifications shall
be included as an appendix to the RMR.
 Finally, the Resource Management Report is not designed to turn the IPUC into a
planning agency nor shall the Report constitute pre-approval of a utility's proposed
resource acquisitions.
 The reporting process is intended to be ongoing-revisions and adjustments are
expected. The utilities should work with the Commission Staff when reviewing and
updating the RMRs. When appropriate, regular public workshops could be helpful and
should be a part of the reviewing and updating process.
 Most parties seem to agree that reducing and/or avoiding peak capacity load or annual
energy load has at least the equivalent effect on system reliability of adding generating
resources of the same size and reliability. Furthermore, because conservation almost
always reduces transmission and distribution system loads, most parties consider
reliability effects of conservation superior to those of generating resources.
Consequently, the Commission finds that electric utilities under its jurisdiction, when
formulating resource plans, should give consideration to appropriate conservation and
demand management measures equivalent to the consideration given generating
resources.
 Therefore, we find that the parties should use the avoided cost methodology resulting
from the No. U-1500-170 case for evaluating the cost effectiveness of conservation
measures. The specific means for comparing No. U-1500-170 case avoided costs to
conservation costs will initially be developed case-by-case as specific conservation
programs are proposed by each utility. Prices to be paid for conservation resources
procured by utilities are discussed later in this Order.
 Give balanced consideration to demand side and supply side resources when
formulating resource plans and when procuring resources.
 Submit to the Commission, no later than March 15, 1989, and at least biennially
thereafter, a Resource Management Report describing the status of its resource
planning as of the most current practicable date.

Order 25260 Requirements
This order documents additional requirements for resource planning including:
 Give full consideration to renewables, among other resource options.
 Investigate and carefully weigh the site-specific potential for particular renewables in
their service area.
 Deviations from the integrated resource plans must be explained. The appropriate
place to determine the prudence of an electric utility's plan or the prudence of an
electric utility's following or failing to follow a plan will be in general rate case or other
proceeding in which the issue is noticed.

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Avista Corp 2021 Electric IRP 2-10
Washington Regulatory Requirements
Washington UTC recently completed its rule making process for Integrated Resource
Planning. The rules are outlined below in Table 2.3 through Table 2.13. Avista also
discusses where in the IRP document the rule requirement is covered or plans to address
the rule requirement in the next IRP.

Table 2.3: Timing & Plan Horizon

WAC Rule Requirement IRP Discussion
WAC 480-100-625
(1) and (4)
Integrated resource plan updated every
four years, with a progress report at least
This IRP begins the new IRP
cycle.
WAC 480-100-620
(1)

Unless otherwise stated, all assessments,
evaluations, and forecasts comprising the
plan should extend over the long-range
(e.g., at least ten years; longer if
appropriate to the life of the resources
This IRP covers 2022 to 2045.

Table 2.4: Load Forecast

WAC Rule Requirement IRP Discussion
WAC 480-100-620
(2)
Plan includes range of forecasts of
projected customer demand that reflect
effect of economic forces on electricity
consumption.

Plan includes range of forecasts of
projected customer demand that address
changes in the number, type, and
Chapter 3 covers the load
forecast and Chapter 12
includes scenarios on
alternative electrical end uses.

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Avista Corp 2021 Electric IRP 2-11
Table 2.5: Demand-Side Resources & DERs

WAC Rule Requirement IRP Discussion
WAC 480-100-620
(3)(a)
WAC 480-109-100
(2)

Plan includes load management
assessments that are cost-effective and
commercially available, including current and
new policies and programs to obtain:
 all cost-effective conservation, efficiency,
and load management improvements;
 ten-year conservation potential used in
the concurrent biennial conservation plan
consistent with RCW 19.285.040(1);
 identification of opportunities to develop
combined heat and power as an energy
and capacity resource; and
 all demand response (DR) at the lowest
Chapter 5 covers the energy
efficiency potential
assessment.

Chapter 6 covers the
demand response potential
assessment.

Chapter 11 covers the
selected energy efficiency
and demand response
options.

WAC 480-100-620
(3)(b)
Plan includes assessments of distributed
energy programs and mechanisms
pertaining to energy assistance and progress
toward meeting energy assistance need,
including but not limited to the following:
 Energy efficiency and CPA,
 Demand response potential,
 Energy assistance potential.

Plan assesses a forecast of distributed
energy resources (DER) that may be
installed by the utility's customers via a
planning process pursuant to RCW
19.280.100(2).

Plan includes effect of DERs on the utility's
load and operations.

If utility engages in a DER planning process,
which is strongly encouraged, IRP should
include a summary of the process planning
Avista includes future
customer DERs with the
load forecast in Chapter 3,
The Company includes
DERs as resource options to
meet future resource
deficits. Lastly, Avista has
not identified any DER
opportunities in its
Distribution Planning at this
time as covered in Chapter
8.

Avista intends to develop a
plan to integrate DERs in
the 2025 IRP (Chapter 14).

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Avista Corp 2021 Electric IRP 2-12
Table 2.6: Supply-Side Resources

WAC Rule Requirement IRP Discussion
WAC 480-100-
620(4)
Plan assesses wide range of
conventional generating resources.
Chapter 9 covers the full list of
supply side resource options
WAC 480-100-
620(5)
In making new investments, plan
considers acquisition of existing and
new renewable resources at LRC.
In Chapter 9, Avista considers
extensions to existing resource
contracts, but does not consider
resources under contract by other
utilities. These resources will
typically be discovered through the
RFP process as Avista has no way
to accurately price these resources
without an RFP.

Avista plans to further assess
existing resource options as part of
UE-151069 & UE-
161024
Plan assesses energy storage
resources.
Chapter 9 covers the full list of
energy storage resources modeled
WAC 480-100-620
(5)
Plan assesses nonconventional
generating, integration, and ancillary
service technologies.
Avista includes the value and cost of
ancillary services for meeting the
flexibility requirements of the system

Table 2.7: Regional Generation & Transmission

WAC Rule Requirement IRP Discussion
WAC 480-100-620
(6)
Plan assesses the availability of
regional generation and transmission
capacity for purposes of delivery of
electricity to customers.

Plan assesses utility's regional
transmission future needs and the
extent transfer capability limitations
may affect the future siting of
Avista assessed regional reliability
in Chapter 7 and the market
analysis in Chapter 10. Regional
transmission planning efforts are
discussed in Chapter 8 and
Appendix G.

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Avista Corp 2021 Electric IRP 2-13
Table 2.8: Resource Evaluation

WAC Rule Requirement IRP Discussion
WAC 480-100-620
(7)
Plan compares benefits and risks of
purchasing power or building new resources.

Plan compares all identified resources
according to resource costs, including:
 transmission and distribution delivery
costs;
 risks, including environmental effects and
the social cost of GHG emissions;
 benefits accruing to the utility, customers,
and program participants (when
applicable); and
 resource preference public policies
adopted by WA State or the federal
government.

Plan includes methods, commercially available
technologies, or facilities for integrating
renewable resources, including but not limited
to battery storage and pumped storage, and
Chapter 11 covers the
selection process of new
supply side and demand
side resources considering
the requirements of this
rule. Additional planning
requirements are also
discussed in Chapter 7
and in Chapter 12.

Table 2.9: Resource Adequacy Metric Determination & Identification

WAC Rule Requirement IRP Discussion
WAC 480-100-620
(8)
Plan assesses and determines resource
adequacy metrics.

Plan identifies an appropriate resource
adequacy requirement.

Plan measures corresponding resource
adequacy metric consistent with prudent utility
practice in eliminating coal-fired generation by
12/31/2025 (RCW 19.405.030), attaining GHG
neutrality by 1/1/2030 (RCW 19.405.040), and
achieving 100 percent clean electricity WA
Avista discusses its
resource adequacy
assessment in Chapter 7
and the resulting resource
adequacy of the PRS in
Chapter 11. Avista also
conducted a resource
adequacy related scenario
in Chapter 12.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Avista Corp 2021 Electric IRP 2-14
Table 2.10: Economic, Health, Environmental Burdens and Benefits, and Equity

WAC Rule Requirement IRP Discussion
WAC 480-100-620
(9)
Plan reflects the cumulative impact
analysis conducted under RCW
19.405.140, and includes an assessment
of:
 energy and nonenergy benefits;
 reduction of burdens to vulnerable
populations and highly impacted
communities;
 long-term and short-term public health
and environmental benefits and costs;
 long-term and short-term public health
and environmental risks; and
 energy security and risk.
Avista covers its current and
future plan to meet this
requirement in Chapter 12.

Table 2.11: Cases, Scenarios, & Sensitivities

WAC Rule Requirement IRP Discussion
WAC 480-100-620
(10)
Utility should include a range of possible
future scenarios and input sensitivities for
testing the robustness of the utility's
resource portfolio under various
parameters, including the following
Chapter 12 covers over 20
portfolio scenarios and four
market scenarios.
CETA counter factual scenario - describe
the alternative LRC and reasonably
available portfolio that the utility would
have implemented if not for the
requirement to comply with RCW
19.405.040 and RCW 19.405.050, as
Avista includes this portfolio as
Portfolio #2, Baseline #1 as
described in Chapter 12.
Climate change scenario - incorporate the
best science available to analyze impacts
including, but not limited to, changes in
snowpack, streamflow, rainfall, heating
and cooling degree days, and load
Avista includes a climate load
forecast for this scenario in
Chapter 3 and discusses
effects of hydro production and
resource analysis in Chapter
Maximum customer benefit sensitivity -
model the maximum amount of customer
benefits described in RCW 19.405.040(8)
prior to balancing against other goals.
Avista has not conducted this
scenario for the 2021 IRP due
to the timing of this
requirement. At this time,
Avista still requires additional
information to determine how to
model this scenario and meet

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Avista Corp 2021 Electric IRP 2-15
Table 2.12: Portfolio Analysis and Preferred Portfolio

WAC Rule Requirement IRP Discussion
WAC 480-100-620
(11)
WAC 480-100-620
(11)(a)
Plan must integrate demand forecasts and
resource evaluations into a long-range IRP
solution.

IRP solution or preferred portfolio must describe
the resource mix that meets current and projected
needs.

Preferred portfolio must include narrative
explanation of the decisions made, including how
the utility's long-range IRP solution:
 achieves requirements for eliminating coal-
fired generation by 12/31/2025 (RCW
19.405.030);
 attains GHG neutrality by 1/1/2030 (RCW
19.405.040);
 achieves 100 percent clean electricity WA
retail sales by 1/1/2045 (RCW 19.405.050) at
LRC; and
 achieves 100 percent clean electricity WA
retail sales by 1/1/2045 (RCW 19.405.050),
Avista plans for many
alternative long-term
load forecasts besides
the Expected Case;
including lower and
higher load growth and
three electrification
scenarios as
discussed in Chapter 3
and in Chapter 12.

For each of these
scenarios, Avista
developed a PRS
subject to the
requirements of this
rule.
WAC 480-100-
620(11)(c)
Consistent with RCW 19.285.040(1), preferred
portfolio shows pursuit of all cost-effective,
reliable, and feasible conservation and efficiency
See Chapter 11.
WAC 480-100-
620(11)(d) and (e)
Preferred portfolio considers acquisition of existing
renewable new resources and relies on renewable
resources and energy storage, insofar as doing so
is at LRC.

Preferred portfolio considers acquisition of existing
renewable new resources and relies on renewable
See Chapter 11.
WAC 480-100-620
(11)(f)
Preferred portfolio maintains and protects the
safety, reliable operation, and balancing of the
utility's electric system, including mitigating over-
generation events and achieving identified
See Chapter 11.
WAC 480-100-620
(11)(g)
Preferred portfolio ensures all customers are
benefiting from the transition to clean energy
through the
 equitable distribution of energy and nonenergy
benefits; reduction of burdens to vulnerable
populations and highly impacted communities;
 long-term and short-term public health and
environmental benefits; reduction of costs and
risks; and
 energy security and resiliency.
Avista is developing
an Equity Advisory
Group to assure all
customers benefit in
the transition to clean
energy. Avista’s plan
for this transition is
covered in Chapter 13.
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Avista Corp 2021 Electric IRP 2-16
WAC 480-100-
620(11)(h)
WAC 480-100-
620(11)(i)
WAC 480-100-
620(11)(j)
Preferred portfolio: assesses the environmental
health impacts to highly impacted communities,
 analyzes and considers combinations of DER
costs, benefits, and operational characteristics
(incl. ancillary services) to meet system needs.
 incorporates the social cost of GHG emissions
as a cost adder.
At this time the full list
of Highly Impacted
Communities is not
available, but it will be
included in the
planning efforts
described in Chapter

Table 2.13: Clean Energy Action Plan

WAC Rule Requirement IRP Discussion
WAC 480-100-620
(12)
Utility must develop a ten-year clean energy action
plan (CEAP) for implementing RCW 19.405.030
through 19.405.050 at LRC, and at an acceptable
resource adequacy standard.

The CEAP will:
 identify and be informed by utility's ten-year
CPA per RCW 19.285.040(1);
 demonstrate that all customers are benefiting
from the transition to clean energy;
 establish a resource adequacy requirement;
 identify the potential cost-effective DR and
load management programs that may be
acquired;
 identify renewable resources, nonemitting
electric generation, and DERs that may be
acquired and evaluate how each identified
resource may be expected to contribute to
meeting the utility's resource adequacy
requirement;
 identify any need to develop new, or expand or
upgrade existing, bulk transmission and
distribution facilities; and
 identify the nature and possible extent to which
the utility may need to rely on alternative
Avista includes a
Clean Energy Action
Plan in Chapter 15 of
this IRP covering each
of the requirements.
WAC 480-100-620
(12)(i)
Plan (both IRP and CEAP) considers cost of
greenhouse gas emissions as a cost adder equal
to the cost per metric ton of carbon dioxide
emissions, using the two and one-half percent
discount rate, listed in Table 2, Technical Support
Document: Technical update of the social cost of
carbon (SCC) for regulatory impact analysis under
Executive Order 12866, published by the
interagency working group on social cost of
greenhouse gases of the United States
government, August 2016, as adjusted by the
Avista includes these
adders discussed in
Chapters 9 - 12 and
includes the
calculation of these
costs in Appendix I.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Chapter 2: Introduction and Stakeholder Involvement
Avista Corp 2021 Electric IRP 2-17
Table 2.14: Avoided Cost

WAC Rule Requirement IRP Discussion
WAC 480-100-620
(13)
Plan must include an analysis and summary of
the estimated avoided cost for each supply-
and demand-side resource, including (but not
limited to):
 energy,
 capacity,
 transmission,
 distribution, and
 GHG emissions.
Listed energy and non-energy impacts should
specify to which source party they accrue
(e.g., utility, customers, participants,
vulnerable populations, highly impacted
Avista estimates avoided
cost including each of the
factors for both supply and
demand side resources.
Chapter 5 includes the
avoided costs for energy
efficiency and Chapter 11
includes the avoided cost
for supply side and
demand response
resources.
WAC 480-106-040 Plan provides information and analysis used to
inform annual purchases of electricity from
qualifying facilities, including a description of
the:
 avoided cost calculation methodology
used;
 avoided cost methodology of energy,
capacity, transmission, distribution, and
emissions averaged across the utility; and
 resource assumptions and market
forecasts used in the utility's schedule of
estimated avoided cost, including (but not
limited to): cost assumptions, production
estimates, peak capacity contribution
estimates, and annual capacity factor
Qualifying Facility avoided
costs calculations are
included in Appendix F.

Table 2.15: Process

WAC Rule Requirement IRP Discussion
WAC 480-100-620
(14)
To maximize transparency, the utility should
submit data input files supporting the plan in
native file format (e.g., supporting
spreadsheets in Excel, not PDF file format).
Avista includes all publicly
available documentation
electronically in Appendix I
and confidential data and
WAC 480-100-620
(16)
Plan must summarize substantive changes to
modeling methodologies or inputs that change
the utility's resource need, as compared to the
This information is
included in Chapter 2.
Utility must
summarize:
Utility must summarize:
 public comments received on the draft
IRP,
 utility's responses to public comments, and
 whether final plan addresses and
Comments and responses
are covered in Appendix
C.
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Chapter 2: Introduction and Stakeholder Involvement
Avista Corp 2021 Electric IRP 2-18
Summary of 2021 IRP Changes from the 2017 and 2020 IRPs
This summary provides an overview of major changes in the analyses since the 2017 and
2020 IRPs. This section does not describe all the specific changes, but rather provides a
summary of the significant or major methodological changes.

Capacity and Energy Position, Including Load Forecasting
 Loads and resources are divided using the Production-Transportation (PT) ratio
and resources must be selected to meet individual state requirements.
 This IRP uses a 16 percent planning margin in the winter rather than the 2017
IRP’s 14 percent. The 7 percent summer planning margin remains the same. This
change retains the 5 percent LOLP threshold assuming 330 MW of market
availability to Avista (compared to 250 MW in the 2017/2020 IRPs).
 The load forecast includes adjustments for natural gas penetration.
 Assumes Colstrip exits Avista’s portfolio by the end of 2025 for Washington
customers and allows the plant to remain in the Idaho portfolio in any year it is
economic.
 Assumes the Northeast CT retires in 2035 and Boulder Park retires in 2040.

Energy Efficiency and Demand Response
 Idaho energy efficiency analysis uses the Utility Cost Test (UCT) for program
selection rather than the Total Resource Cost (TRC) test.
 Washington energy efficiency analysis includes savings from associated
greenhouse gas emissions priced at the social cost of carbon using the 2.5 percent
discount rate prescribed in CETA. The emissions savings assumes the annual
incremental emission rate within the regional power system. Avista used average
regional emissions in the 2020 IRP and a portfolio scenario was conducted to test
this difference in this IRP.
 Estimates for non-energy impacts are included in the avoided cost.
 The 2021 IRP estimated energy savings for DR programs and includes the energy
savings in the portfolio analysis.

Supply-Side Resource Options
 Avista modeled several energy storage options in this IRP including specific
regional projects and representative pumped hydro storage projects. Transmission
and Distribution scale lithium-ion storage along with vanadium flow, zinc bromide
flow, and liquid air storage options were also modeled for this IRP.
 Hydrogen fuel is considered using both fuel cells and turbines with on-site storage.
 This IRP models wind, solar, pumped hydro storage, nuclear and geothermal as
purchase power agreements; whereas the IRPs prior to 2020 assumed these
resources were Avista-owned.
 Avista assigned peak credits to renewable and storage resources depending on a
resource’s ability to meet peak loads determined using its ARAM model.
 The 2021 plan, for the first time, uses levelized energy or capacity cost rather than
annual cost estimates for all resource options.
 This IRP includes upstream greenhouse gas emissions from the natural gas-fired
projects priced with the social cost of carbon for Washington’s share of resources.
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Avista Corp 2021 Electric IRP 2-19
 Construction and operational greenhouse gas emissions are considered and
priced using the social cost of carbon for Washington’s share of resources.
 The IRP analysis does not use a social cost of carbon price for market purchases
and sales as in the 2020 IRP. A portfolio scenario was performed to test this
sensitivity.

Market Analysis
 Avista utilizes Energy Exemplar’s (Aurora) database for most inputs into the price
forecast with the exception of Avista’s proprietary utility specific information.
 The Aurora capacity expansion study is required to meet the qualifications of state
clean energy policies including CETA using both a national consulting database
and Aurora’s capacity expansion logic. The model must also meet a 5 percent
LOLP threshold for reliability when selecting new resources.
 This IRP blends two consultant forecasts and the Energy Information System (EIA)
long-term forecasts with market forward prices for the natural gas price forecast.
The 2017 IRP used only one consultant forecast along with forward prices and the
2020 IRP did not include the EIA forecast.

Portfolio Optimization Analysis
 The 2021 IRP optimizes a resource portfolio for 2022 to 2045. Moving to 24 years
led to removing some of the cost estimates for resources beyond 20 years.
 The social cost of carbon is not included in the projected dispatch decision of
resources in the Expected Case but is included in the optimization of resource
decisions, which is the same methodology used in the 2020 IRP.
 This IRP models the clean energy requirements of CETA in Washington State the
same as the 2020 IRP.
 Includes total customer rate estimates. IRPs prior to 2020 only showed power
supply costs.
 Portfolio optimization allows new resources to be added for either state or the
system to understand the drivers and responsibility of resource decisions.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Chapter 3: Economic & Load Forecast

Avista Corp 2021 Electric IRP 3-1
3. Economic & Load Forecast

Avista’s loads and resources are an integral component of the IRP. This chapter
summarizes customer and load projections; including high and low load growth scenarios;
adjustments for customer-owned solar generation, electric vehicles and climate change,
as well as recent enhancements to load and customer forecasting models and processes.

Economic Characteristics of Avista’s Service Territory
Avista’s core electric service area includes more than a half million people residing in
Eastern Washington and Northern Idaho. Three metropolitan statistical areas (MSAs)
dominate its service area: the Spokane-Spokane Valley, WA MSA (Spokane-Stevens
counties); the Coeur d’Alene, ID MSA (Kootenai County); and the Lewiston-Clarkson ID-
WA, MSA (Nez Perce-Asotin counties). These three MSAs account for just over 70
percent of both Avista’s customers (i.e., meters) and load. The remaining 30 percent are
in low-density rural areas in both states. Washington accounts for about two-thirds of
customers and Idaho the remaining one-third. The IRP forecast period 2021-2025
includes the impacts of the COVID-19 shock since the forecast was completed following
the national shut-down for the pandemic in the first quarter of 2020. By 2025, the IRP
assumes both the U.S. and Avista service area economies will largely return to pre-
COVID-19 long-run economic growth.

Population
Population growth is increasingly a function of net migration within Avista’s service area.
Net migration is strongly associated with both service area and national employment
growth through the business cycle. The regional business cycle follows the U.S. business
cycle, meaning regional economic expansions or contractions follow national trends.1
Econometric analysis shows when regional employment growth is stronger than U.S.
growth over the business cycle, it is associated with increased in-migration and the
reverse holds true. Figure 3.1 shows annual population growth since 1971 and highlights
the recessions in yellow. During all deep economic downturns since the mid-1970s,
reduced population growth rates in Avista’s service territory led to lower load growth.2 The

1 An Exploration of Similarities between National and Regional Economic Activity in the Inland Northwest,
Monograph No. 11, May 2006. http://www.ewu.edu/cbpa/centers-and-institutes/ippea/monograph-
series.xml.
2 Data Source: Bureau of Economic Development, U.S. Census, and National Bureau of Economic
Research.
Chapter Highlights
 The 2021 energy forecast grows 0.3 percent per year, similar to the 0.3 percent
annual growth rate in the 2020 IRP.
 Peak load growth is 0.38 percent in the winter and 0.44 percent in the summer.
 Retail sales and residential use per customer forecasts are slightly higher than
the 2020 IRP projections.
 Avista expects a 39 aMW increase in residential load from electric vehicles and
a decrease of 12 aMW due to residential rooftop solar by 2045.
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Avista Corp 2021 Electric IRP 3-2
Great Recession reduced population growth from nearly 2 percent in 2007 to less than 1
percent from 2010 to 2013. Accelerating service area employment growth in 2013 helped
push population growth to around 1 percent starting in 2014.

Figure 3.1: MSA Population Growth and U.S. Recessions, 1971-2019

Figure 3.2 shows population growth since the start of the Great Recession in 2007.3
Service area population growth over the 2010-2012 period was weaker than the U.S.;
however, it was closely associated with the strength of regional employment growth
relative to the U.S. over the same period. The same can be said for the increase in service
area population growth in 2014 relative to the U.S. population growth. The association of
employment growth to population growth has a one-year lag. The relative strength of
service area population growth in year “y” is positively associated with service area
population growth in year “y+1”. Econometric estimates using historical data show when
holding the U.S. employment-growth constant, every 1 percent increase in service area
employment growth is associated with a 0.4 percent increase in population growth in the
next year.

3 Data Source: Bureau of Economic Analysis, U.S. Census, and Washington State OFM.
-1.0%
-0.5%
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
3.0%
3.5%
19
7
1
19
7
3
19
7
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7
7
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7
9
19
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Avista Corp 2021 Electric IRP 3-3
Figure 3.2: Avista and U.S. MSA Population Growth, 2007-2019

Employment
It is useful to examine the distribution of employment and employment performance since
2007 given the correlation between population and employment growth. The Inland
Northwest is now a services-based economy rather than its former natural resources-
based manufacturing economy. Figure 3.3 shows the breakdown of non-farm
employment for all three-service area MSAs.4 Approximately 70 percent of employment
in the three MSAs is in private services, followed by government (17 percent) and private
goods-producing sectors (14 percent). Farming accounts for 1 percent of total
employment. Spokane and Coeur d’Alene MSAs are major providers of health and higher
education services to the Inland Northwest.

4 Data Source: Bureau of Labor and Statistics.
0.8%
0.5%0.5%
0.7%
1.0%
1.2%
1.7%
1.9%
1.7%
1.5%
0.8%
0.7%0.7%0.7%0.7%0.7%0.7%
0.6%0.6%0.6%
0.0%
0.2%
0.4%
0.6%
0.8%
1.0%
1.2%
1.4%
1.6%
1.8%
2.0%
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Avista WA-ID MSAs
U.S.
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Avista Corp 2021 Electric IRP 3-4
Figure 3.3: MSA Non-Farm Employment Breakdown by Major Sector, 2019

Non-farm employment growth averaged 2.7 percent per year between 1990 and 2007.
However, Figure 3.4 shows service area employment lagged the U.S. recovery from the
Great Recession for the 2010-2012 period.5 Regional employment recovery did not
materialize until 2013, when services employment started to grow. Prior to this, reductions
in federal, state and local government employment offset gains in goods producing
sectors. Service area employment growth began to match or exceed U.S. growth rates
by the fourth quarter 2014. It is worth noting the exact timing of Avista’s service area’s
recovery from the COVID-19 recession is uncertain. However, the 2021 IRP forecast
assumes a GDP decline of 6 percent in 2020, with a gradual recovery to pre-COVID-19
long-term economic growth by 2025. The steep decline in GDP in 2020 translates into an
industrial load forecast that will not fully normalize until after 2025. In addition, the forecast
includes statistical control variables assuming the large COVID-19 induced load shifts
between residential and commercial customers will last into 2025, but with the large
difference initially created in 2020 narrowing as economic activity normalizes. Avista will
continue to monitor the post-recession load levels and distribution for future IRPs.

5 Data Source: Bureau of Labor and Statistics.
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Avista Corp 2021 Electric IRP 3-5
Figure 3.4: Avista and U.S. MSA Non-Farm Employment Growth, 2010-2019
Figure 3.5 shows the distribution of personal income, a broad measure of both earned
income and transfer payments, for Avista’s Washington and Idaho MSAs.6 Regular
income includes net earnings from employment, and investment income in the form of
dividends, interest and rent. Personal current transfer payments include money income
and in-kind transfers received through unemployment benefits, low-income food
assistance, Social Security, Medicare and Medicaid.

Transfer payments in Avista’s service area in 1970 accounted for 12 percent of the local
economy. The income share of transfer payments has nearly doubled over the last 40
years to 22 percent. The relatively high regional dependence on government employment
and transfer payments means transfer program reform may reduce future local economic
growth. Although 57 percent of personal income is from net earnings, transfer payments
still account for more than one in every five dollars of personal income. Recent years
have seen transfer payments become the fastest growing component of regional personal
income. This growth in regional transfer payments reflects an aging regional population,
a surge of military veterans and the Great Recession; the latter significantly increased
payments from unemployment insurance and other low-income assistance programs.

Figure 3.6 shows the real (inflation adjusted) average annual growth per capita income
by MSA for Avista’s service area and the U.S. overall. Note that in the 1980 – 1990 period,
the service area experienced significantly lower income growth compared to the U.S.
because of the back-to-back recessions of the early 1980s.7 The impacts of these
recessions were more negative in the service area compared to the U.S. as a whole, so
the ratio of service area per capita income to U.S. per capita income fell from 93 percent

6 Data Source: Bureau of Economic Analysis.
7 Data Source: Bureau of Economic Analysis.
-1.6%
0.2%
0.6%
2.0%1.8%1.9%
3.0%
2.0%2.1%
1.5%
-0.7%
1.2%
1.7%1.6%
1.9%2.1%
1.8%1.6%1.7%
1.4%
-3.5%
-2.5%
-1.5%
-0.5%
0.5%
1.5%
2.5%
3.5%
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
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Chapter 3: Economic & Load Forecast

Avista Corp 2021 Electric IRP 3-6
in the 1970s to around 85 percent by the mid-1990s. The income ratio has not since
recovered.

Figure 3.5: MSA Personal Income Breakdown by Major Source, 2019

Figure 3.6: Avista and U.S. MSA Real Personal Income Growth by Decade, 1970-2019

Overview of the Retail Load Forecast
The retail load forecast is a two-step process. The first step is a detailed five-year forecast
described below and the second steps bootstraps years six through 25 by applying the
growth assumptions discussed later in this chapter. For each customer class in most rate
schedules, there is a monthly use per customer (UPC) forecast and a monthly customer
Net Earnings, 57%
Dividends, Interest,
and Rent, 21%
Transfer Receipts,
22%
2.4%
1.3%
2.3%
0.8%
2.1%2.1%
2.3%2.4%
0.8%
2.2%
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
3.0%
1970 to 1980 1980 to 1990 1990 to 2000 2000 to 2010 2010 to 2019
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Chapter 3: Economic & Load Forecast

Avista Corp 2021 Electric IRP 3-7
forecast.8 The load forecast results from multiplying the customer and UPC forecasts.
The UPC and customer forecasts are generated using time-series econometrics, as
shown in Equation 3.1.

Equation 3.1: Generating Schedule Total Load
𝐹(𝑘𝑊ℎH,HHH,H) = 𝐹(𝑘𝑊ℎ/𝐶H,HHH,H) × 𝐹(𝐶H,HHH,H)
Where:
 F(kWhH,HHH,H) = the forecast for month t, year j = 1,…,5 beyond the
current year, yc ,for schedule s.
 F(kWh/CH,HHH,H) = the UPC forecast.
 F(CH,HHH,H) = the customer forecast.

UPC Forecast Methodology
The econometric modeling for UPC is a variation of the “fully integrated” approach
expressed by Faruqui (2000) in the following equation:9

Equation 3.2: Use Per Customer Regression Equation
𝑘𝑊ℎ/𝐶H,H,H= 𝛼𝑊H,H+ 𝛽𝑍H,H+ 𝜖H,H

The model uses actual historical weather, UPC and non-weather drivers to estimate the
regression in Equation 3.2. To develop the forecast, normal weather replaces actual
weather (W) along with the forecasted values for the Z variables (Faruqui, pp. 6-7). Here,
W is a vector of heating degree day (HDD) and cooling degree day (CDD) variables; Z is
a vector of non-weather variables; and εt,y is an uncorrelated N(0,σ) error term. For non-
weather sensitive schedules, W = 0.

The W variables will be HDDs and CDDs. Depending on the schedule, the Z variables
may include real average energy price (RAP); the U.S. Federal Reserve industrial
production index (IP); residential natural gas penetration (GAS); non-weather seasonal
dummy variables (SD); trend functions (T); and dummy variables for outliers (OL) and
periods of structural change (SC). RAP is measured as the average annual price
(schedule total revenue divided by schedule total usage) divided by the consumer price
index (CPI), less energy. For most schedules, the only non-weather variables are SD, SC
and OL. See Table 3.1 for the occurrence RAP and IP.

If the error term appears to be non-white noise, then the forecasting performance of
Equation 3.2 can be improved by converting it into an autoregressive integrated moving
average (ARIMA) “transfer function” model such that Єt,y = ARIMAЄt,y(p,d,q)(pk,dk,qk)k.
The term p is the autoregressive (AR) order, d is the differencing order, and q is the
moving average (MA) order. The term pk is the order of seasonal AR terms, dk is the order

8 For schedules representing a single customer, where there is no customer count and for street lighting,
Avista forecasts total load directly without first forecasting UPC.
9 Faruqui, Ahmad (2000). Making Forecasts and Weather Normalization Work Together, Electric Power
Research Institute, Publication No. 1000546, Tech Review, March 2000.
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Avista Corp 2021 Electric IRP 3-8
of seasonal differencing, and qk is the seasonal order of MA terms. The seasonal values
relate to “k,” or the frequency of the data. With the current monthly data set, k = 12.

Certain schedules, such as those related to lighting, use simpler regression and
smoothing methods because they offer the best fit for irregular usage without seasonal
or weather-related behavior, is in a long-run steady decline, or is seasonal and unrelated
to weather. Avista defines normal weather for the load forecast as a 20-year moving
average of degree-days taken from the National Oceanic and Atmospheric
Administration’s Spokane International Airport data. Normal weather updates only occur
when a full year of new data is available. For example, normal weather for 2018 is the 20-
year average of degree-days for the 1998 to 2017 period; and 2019 is the average of the
1999 to 2018 period.

The choice of a 20-year moving average for defining normal weather reflects several
factors. First, climate research from the National Aeronautics and Space Administration’s
(NASA) Goddard Institute for Space Studies (GISS) shows a shift in temperature starting
almost 30 years ago. The GISS research finds the summer temperatures in the Northern
Hemisphere increased one degree Fahrenheit above the 1951-1980 reference period;
the increase started roughly 30 years ago in the 1981-1991 period.10 An in-house analysis
of temperature in Avista’s Spokane-Kootenai service area, using the same 1951-1980
reference period, also showed an upward shift in temperature starting about 30-years
ago. A detailed discussion of this analysis is provided in the peak-load forecast section of
this chapter.

The second factor in using a 20-year moving average is the volatility of the moving
average as a function of the years used to calculate the average. Moving averages of 10
and 15 years showed considerably more year-to-year volatility than the 20-year moving
average. This volatility can obscure longer-term trends and leads to overly sharp changes
in forecasted loads when applying the updated definition of normal weather each year.
These sharp changes would also cause excessive volatility in the revenue and earnings
forecasts.

As noted earlier, if non-weather drivers appear in Equation 3.2, then they must also be in
the five-year forecast to generate the UPC forecast. The assumption in the five-year
forecast for this IRP is for RAP to be constant out to 2025; increase at 1 percent from
2026 to 2029; and then increase 1.5 percent until 2045. RAP no longer appears explicitly
in the regression equations for the five-year forecast. The coefficient estimates for RAP
have become unstable and statistically insignificant. Therefore, the 2021 IRP assumes
elasticity to be -0.3 percent, based on long-run estimates from academic literature.11 This

10 See Hansen, J.; M. Sato; and R. Ruedy (2013). Global Temperature Update Through 2012,
http://www.nasa.gov/topics/earth/features/2012-temps.html.
11 Avista is unable to produce reliable elasticity estimates using its own UPC data. It is difficult to obtain
reliable elasticity estimates using data for an individual utility, so the Company relies on academic estimates
using multiple regions and estimation methods. As theory predicts, the literature indicates that short-term
elasticity is lower (less price sensitive) than long-term elasticity. Avista assumes the low end of the long-
term range of academic elasticity estimates.
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Avista Corp 2021 Electric IRP 3-9
IRP generates IP forecasts from a regression using the GDP growth forecasts (GGDP).
Figure 3.7 describes this process.

Table 3.1: UPC Models Using Non-Weather Driver Variables

Schedule Variables Comment
Washington:
Residential Schedule 1 GAS Ratio of natural gas residential schedule 101
customers in WA to electric residential schedule

Idaho:
Residential Schedule 1 GAS Ratio of natural gas residential schedule 101
customers in ID to electric residential schedule

The forecasts for GDP reflect the average of forecasts from multiple sources including
the Bloomberg survey of forecasts, the Philadelphia Federal Reserve survey of
forecasters, the Wall Street Journal survey of forecasters and other sources. Averaging
forecasts reduces the systematic errors of a single-source forecast. This approach
assumes macroeconomic factors flow through UPC in the industrial rate schedules. This
reflects the relative stability of industrial customer growth over the business cycle.

Figure 3.7: Forecasting IP Growth

Average GDP
Growth Forecasts:
IMF, FOMC,
Bloomberg, etc.
Average
forecasts out 5-
yrs.
U.S Industrial Production
Index (IP) Growth Model:
Model links year y
GDP growth year y IP
growth. Federal Reserve
industrial production
index is measure of IP
growth. Forecast out 5-years.
Generate Average, High, and Low
IP Forecast:
Forecast annual IP growth
using the GDP forecast
average (the baseline
scenario), a “high” scenario,
and a “low” scenario.
The high and low GDP
forecasts are the annual high
and low values from the
various sources used to
generate the average GDP
growth rate in each year.
Apply scenario that makes
most sense given the most
current economic analysis.
Convert annual growth
scenario to a monthly basis to
project out the monthly level of
the IP.
GDP IP
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Avista Corp 2021 Electric IRP 3-10
Figure 3.8 shows the historical relationship between the IP and industrial load for
electricity.12,13 The load values have been seasonally adjusted using the Census X11
procedure. The historical relationship is positive for both loads. The relationship is very
strong for electricity with the peaks and troughs in load occurring in the same periods as
the business cycle peaks and troughs.

Figure 3.8: Industrial Load and Industrial (IP) Index

Customer Forecast Methodology
The econometric modeling for the customer models range from simple smoothing models
to more complex ARIMA models. In some cases, a pure ARIMA model without any
structural independent variables is used. For example, the independent variables are only
the past values of the rate schedule customer counts, which is also the dependent
variable. Because the customer counts in most rate schedules are either flat or growing
in a stable fashion, complex econometric models are generally unnecessary for
generating reliable forecasts. Only in the case of certain residential and commercial
schedules is more complex modeling required.

For the main residential and commercial rate schedules, the modeling approach needs
to account for customer growth between these schedules having a high positive
correlation over 12-month periods. This high customer correlation translates into a high
correlation over the same 12-month periods. Table 3.2 shows the correlation of customer
growth between residential, commercial and industrial consumers of Avista electricity and
natural gas. To assure this relationship in the customer and load forecasts, the models
for the Washington and Idaho Commercial Schedules 11 use Washington and Idaho
Residential Schedule 1 customers as a forecast driver. Historical and forecasted

12 Data Source: U.S. Federal Reserve and Avista records.
13 Figure 3.8 excludes one large industrial customer with significant load volatility.
50
60
70
80
90
100
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70 GWh
80 GWh
90 GWh
100 GWh
110 GWh
120 GWh
130 GWh
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Industrial, SA Industrial, Trend-Cycle Industrial Production
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 53 of 317
Chapter 3: Economic & Load Forecast

Avista Corp 2021 Electric IRP 3-11
Residential Schedule 1 customers become drivers to generate customer forecasts for
Commercial Schedule 11 customers.

Table 3.2: Customer Growth Correlations, January 2005 – October 2020

Customer Class Residential Commercial Industrial Streetlights
Residential 1
Commercial 0.61 1.00
Industrial -0.06 0.12 1.00
Streetlights -0.18 -0.08 0.13 1.00

Figure 3.9 shows the relationship between annual population growth and year-over-year
customer growth.14 Customer growth has closely followed population growth in the
combined Spokane-Kootenai MSAs over the last 20 years. Population growth averaged
1.3 percent over the 2000-2019 period and customer growth averaged 1.2 percent
annually.

Figure 3.9 demonstrates how population growth is a proxy for customer growth. As a
result, forecasted population is an adjustment to Residential Schedule 1 customers in
Washington and Idaho. The forecast is made using an ARIMA times-series model for
Schedule 1 customers in Washington and Idaho. If the growth rates generated from this
approach differ from forecasted population growth, the forecast adjusts to match
forecasted population growth.

Figure 3.9: Population Growth vs. Customer Growth, 2000-2019

14 Data Source: Bureau of Economic Analysis, U.S. Census, Washington State OFM, and Avista records.
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
An
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G
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Avista WA-ID MSAs
System Customers
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 54 of 317
Chapter 3: Economic & Load Forecast

Avista Corp 2021 Electric IRP 3-12
Forecasting population growth is a process that links U.S. GDP growth to service area
employment growth and then links regional and national employment growth to service
area population growth.
The same average GDP growth forecasts used for the IP growth forecasts are inputs to
the five-year employment growth forecast. Avista averages employment forecasts with
IHS Connect’s (formerly Global Insight) forecasts for the same counties. Averaging may
reduce the systematic errors of a single-source forecast. The averaged employment
forecasts become inputs to generate population growth forecasts. Figure 3.10
summarizes the forecasting process for population growth for use in estimating
Residential Schedule 1 customers.

Figure 3.10: Forecasting Population Growth

The employment growth forecasts (the average of Avista and IHS forecasts) become
inputs used to generate the population growth forecasts. The Kootenai forecast is
averaged with IHS’s forecasts for the same MSA. The Spokane forecast is averaged with
Washington’s Office of Financial Management (OFM) forecast for the same MSA. These
averages produce the final population forecast for each MSA. These forecasts are then
converted to monthly growth rates to forecast population levels over the next five years.

IRP Long-Run Load Forecast
The Basic Model
The long-run load forecast extends the intermediate term projection out to 2045. It
includes the adjustments for electric vehicle (EV) fleet and residential rooftop photovoltaic
(PV) solar. The long-run modeling approach starts with Equation 3.3.

Equation 3.3: Residential Long-Run Forecast Relationship
ℓH = 𝑐H + 𝑢H
Where:
 ℓy = residential load growth in year y.
 cy = residential customer growth in year y.
 uy = UPC growth in year y.
Average GDP
Growth Forecasts:
IMF, FOMC,
Bloomberg, etc.
Average
forecasts out 5-
years.
Regional Population Growth Models:
Model links regional, U.S., and CA year y-1
employment growth to year y county
population growth.
Forecast out 5-years for Spokane, WA and
Kootenai, ID.
Averaged with IHS forecasts in ID and OFM
forecasts in WA.
Growth rates used to generate population
forecasts for customer forecasts for
residential schedule 1.
Non-farm Employment
Growth Model:
Model links year y, y-
1, and y-2 GDP
growth to year y
regional employment
growth. Forecast out 5-
years.
Averaged with IHS
forecasts.
GDP
EMP
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 55 of 317
Chapter 3: Economic & Load Forecast

Avista Corp 2021 Electric IRP 3-13
Equation 3.3 sets annual residential load growth equal to annual customer growth plus
the annual UPC growth.15 Cy is not dependent on weather, so where uy values are
weather normalized, ℓy results are weather-normalized. Varying cy and uy generates
different long-run forecast simulations. This IRP varies cy for economic reasons and uy
for increased usage of PV, EVs and LED lighting.

Expected Case Assumptions
The forecast makes the following assumptions about the long-run relationship between
residential, commercial and industrial classes.

1. As noted earlier, long-run residential and commercial customer growth rates are
linked, consistent with historical growth patterns with a positive correlation between
the two (see Table 3.2). Figure 3.11 shows the time path of residential customer
growth. The average annual growth rate after 2025 is approximately 0.8 percent, with
a gradual decline out to 2045. The generated values shown in Figure 3.11 use the
Employment and Population forecasts in conjunction with IHS’s employment and
population forecasts and Washington’s OFM population forecasts. Starting in 2026, it
assumes annual commercial customers increase 0.08 percent for each one
percentage point increase in residential customer growth. This relationship is
consistent with both long-run annual regression relationships and monthly ARIMA
forecast models where residential customers are used as the forecast driver. The
annual average growth rate of commercial customers after 2025 is approximately 0.66
percent. The annual industrial customer growth rate assumption is -0.66 percent after
2025, which is equivalent to a decline of seven industrial customers a year through
2045. This assumption reflects an ongoing long-run decline in industrial customers
experienced by Avista since 2005.

2. Commercial load growth follows changes in residential load growth. This positive
correlation assumption is consistent with the high historical correlation seen between
residential and commercial load growth. The connection, based on a linear regression
linking commercial UPC growth to residential UPC growth, assumes that for every 1
percent point change in residential UPC growth, commercial UPC will change by 0.23
percent.

3. Consistent with historical behavior, industrial and streetlight load growth projections
do not correlate with residential or commercial load. Annual industrial load growth is
near zero percent after 2025. This reflects the assumption that the annual -0.66
percent decline in industrial customer growth is offset by UPC growth driven by long-
run economic growth. The streetlight load growth is zero percent after 2025 to reflect
the assumption of slow customer growth being offset by the impact of LED lighting.

15 Since UPC = load/customers, calculus shows the annual percentage change UPC ≈ percentage change
in load - percentage change in customers. Rearranging terms, the annual percentage change in load ≈
percentage change in customers + percentage change in UPC.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 56 of 317
Chapter 3: Economic & Load Forecast

Avista Corp 2021 Electric IRP 3-14
Figure 3.11: Long-Run Annual Residential Customer Growth

4. As noted earlier, the assumption in the five-year forecast for this IRP is for the RAP to
be constant through 2025; increase at 1 percent annually between 2026 and 2029;
and then increase 1.5 percent yearly until 2045. RAP no longer appears explicitly in
the regression equations for the five-year forecast. The coefficient estimates for the
RAP have become unstable and statistically insignificant. Therefore, the 2021 IRP
assumes own-price elasticity to be -0.3 percent, based on long-term estimates from
the academic literature (See also footnote 11).

5. Avista estimates 2,000 Electric Vehicles (EV) are currently within its service area. The
forecasted rate of adoption over the 2021-2045 period assumes 107,000 EVs will be
in the service area by 2045. Between 2021 and 2045, the implied annual growth rate
is 16 percent. The forecast assumes each EV uses 3,153 kWh per year, to be
consistent with the value used in Avista’s 2020 Transportation Electrification Plan. The
EV forecast reflects residential light duty vehicles only. Based on the assumption of
approximately two vehicles per residential customer (based on U.S. Census data for
our service area), the EV penetration rate is forecasted to rise from 0.3 percent of
residential customers today to just over 13 percent by 2045 for a total load of 39 aMW.
See Figure 3.12.

There are three significant barriers to the rapid, near-term accumulation of EVs. The
first is consumer preferences related to model options (i.e., sedans, SUVs, and
pickups) and battery range. Although these barriers are slowly shrinking, the gap with
traditional internal combustion vehicles is still notable. This is important in Avista’s
service area given the significant number of rural and suburban households with
strong preferences for pickup trucks and SUVs for both commuting, utility and
recreational use. Second, there is consumer uncertainty about the evolution of the
0.5%
0.6%
0.7%
0.8%
0.9%
1.0%
1.1%
1.2%
20
2
1
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2
2
20
2
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G
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w
t
h
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 57 of 317
Chapter 3: Economic & Load Forecast

Avista Corp 2021 Electric IRP 3-15
public charging infrastructure to support rapid adoption in the near term. Although
improving, the public charging infrastructure remains significantly underdeveloped
compared to traditional vehicles. Third is the willingness of consumers to rapidly
abandon traditional vehicles, while still being relatively new, for EVs with similar
characteristics that may require a higher upfront cost. Because of these barriers, this
IRP, as with the 2017 and 2020 IRPs, assumes rapid adoption will not start until the
early 2030s in Avista’s service area. This is reflected in the assumption that the
number of EVs will follow an exponential growth function with a 16 percent growth
rate. Finally, although not directly calculated, the impact of EVs on commercial usage
is indirectly accounted for by the assumed positive correlation between residential and
commercial UPC.

6. Rooftop solar penetration, measured as the share of residential solar customers to
total residential customers, continues to grow at present levels in the forecast. The
starting average solar system is set at 7 kW (DC) with a 13 percent capacity factor, or
about 7,800 kWh per year per customer. These values reflect current Company data
on customer installation size and system efficiency. The IRP assumes the starting
system size will increase 1 percent annually to about 10,100 kWh per year per
customer in 2045, with the capacity factor remaining constant at 13 percent. Company
data on its residential customers show the system size is increasing over time. In the
2005-2008 period, when solar installs were just beginning, the median installed
system size was about 1.8 kW. This IRP assumes the residential PV penetration rate
will continue to follow a non-linear relationship between the historical penetration rate
in year t and the historical number of residential customers in year t. Under this
assumption, residential solar penetration will increase from 0.3 percent in 2019 to
about 2.5 percent in 2045.This accumulation can be approximated by an exponential
growth function. The base-line model assumes residential solar penetration will grow
at approximately 8 percent annually through 2045 for approximately 12 aMW in load
reduction- See Figure 13.12. Both the growth in solar system size and penetration are
estimates and this information will be monitored for possible adjustment in future IRPs.

There are several important barriers around the accumulation of residential PV
systems in our service area. First, urban and rural forests surround many of the owner-
occupied homes in our service area. Tree shade can significantly reduce solar
generation. In the Spokane metro area, the largest metro area we serve, many of the
areas with fewer trees are lower-income areas and/or are mainly composed of renter-
occupied residences. Second, the heavy winter cloud cover also reduces solar
generation. The Company recognizes future improvements in solar panels can reduce
these barriers. For example, solar panels can be formed directly into roof top shingles
or home siding. The assumed penetration of solar has increased in every IRP since
2015. Finally, as with EVs, the impact of solar penetration for commercial customers
is indirectly accounted for by the assumed positive correlation between residential and
commercial UPC.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 58 of 317
Chapter 3: Economic & Load Forecast

Avista Corp 2021 Electric IRP 3-16
Figure 3.12: Electric Vehicle and Rooftop Solar Load Changes

Native Load Scenarios with Low/High Economic Growth
The load forecast for this IRP also considers futures with higher and lower loads. The
high and low load scenarios use the population growth in Table 3.3, holding long-run U.S.
employment growth constant at 0.4 percent (a Bureau of Labor Statistics forecast for the
2019-2029 period), but varying MSA employment growth at higher and lower levels to
gauge the impacts on population growth and subsequent utility loads. This approach
assumes customer growth, and not UPC, is most likely to be impacted by differences in
economic growth rates between the Company’s service area and the U.S.in general.

Historical evidence shows population growth (a proxy for customer growth) tends to
increase as regional growth improves relative to the U.S. growth level. That is, as the
regional economy gains strength relative to the U.S., in-migration accelerates. This is
done using coefficient estimates from the Company’s medium-term population growth
forecast models referred to in Figure 3.10. The high/low range for growth in the service
area reflects the impact on forecasted population growth by varying service area
employment growth while holding U.S. employment growth constant at 0.4 percent.
Simulated population growth is a proxy for residential customer growth in the long-run
forecast model and produces the high and low native load forecasts in Figure 3.13.

-5
0
5
10
15
20
25
30
35
40
45
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a
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M
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g
a
w
a
t
t
s
Rooftop Solar Load Reduction
Electric Vehicle Load Addition
Net Load Change
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 59 of 317
Chapter 3: Economic & Load Forecast

Avista Corp 2021 Electric IRP 3-17
Equation 3.4: Residential Long-Run Forecast Relationship

𝑃𝑂𝑃𝐺 =(0.005 + 𝑎H0.004HH+ 𝑎H𝐸𝑀𝑃𝐺HHH)∙ 𝑊 +(0.005 + 𝑏H0.004HH+ 𝑏H𝐸𝑀𝑃𝐺HHHH)
∙ (1 − 𝑊)

Where:

 POPG = predicted population growth rate for the combined Spokane-Kootenai
metro area.
 a = the estimated regression coefficients from the Spokane metro population
growth forecast equation used for the medium-term forecast. These reflect the
sensitivities of a change in U.S. employment growth (a1<0) and Spokane metro
employment growth (a2>0) on Spokane metro population growth. Note that 0.004
is the BLS forecast for long-run U.S. employment growth and EMPGSPK is the
assumed high/low growth rate for Spokane metro.
 b = the estimated regression coefficients from the Kootenai metro population
growth forecast equation medium-term forecast. These reflect the sensitivities of a
change in U.S. employment growth (b1<0) and Kootenai metro employment growth
(b2>0) Kootenai metro population growth. Note that 0.004 is the BLS forecast for
long-run U.S. employment growth and EMPGKOOT is the assumed high/low growth
rate for the Kootenai metro area.
 0.005 = the intercept term replacing the original intercept from the medium-term
regression equations. It reflects the long-term U.S. Census forecast for annual U.S.
population growth (0.5 percent) over the IRP’s forecast period. The assumption
here is if annual service area employment growth and U.S. employment growth
are the same, regional population growth will converge to the U.S. level over time.
This assumes that if regional employment growth is the same as the U.S. (0.4%
annually), the incentive for people to migrate to the combined metro region for
economic reasons goes away.
 W = the share of population in the Spokane metro as a share of the total population
the combined Spokane-Kootenai metro area. This provides a weight to produce a
combined area population growth rate.

The high and low values in Table 3.3 were chosen based on the historical distribution of
service area employment growth relative to the U.S. employment growth. From 1990 to
2019 (pre-COVID-19), annual service area employment growth exceeded U.S. growth by
an average of 0.9 percent, which is statistically different from zero at the 95 percent level.
The low growth scenario is set where the annual growth spread is zero percent and the
high growth case is 1.5 percent. The historical distribution of the annual growth spread
places a zero spread and 1.5 spread at approximately the 25th and 75th percentiles,
respectively. It should be noted however, for 2021-2022, the high/low bounds shown in
Figure 3.13 were widened beyond what was suggested by Equation 3.4 because of the
Company’s uncertainty over the shorter-term impacts COVID-19 on load behavior.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 60 of 317
Chapter 3: Economic & Load Forecast

Avista Corp 2021 Electric IRP 3-18
Table 3.3: High/Low Economic Growth Scenarios (2021-2045)

Annual U.S.
Employment Growth
(percent)
Annual Service Area
Employment Growth
(percent)
Annual Population
Growth
(percent)
Expected Case 0.40 1.00 0.80
High Growth 0.40 1.90 1.20
Low Growth 0.40 0.40 0.50

Figure 3.13: Average Megawatts, High/Low Economic Growth Scenarios

Table 3.4 shows the average annual load growth rate over the 2021-2045 period. The
low growth scenario predicts a slight load decline over the 2025-2041 timeframe.

Table 3.4: Load Growth for High/Low Economic Growth Scenarios (2021-2045)

Growth
(percent)
Expected Case 0.30
High Growth 0.70
Low Growth -0.10

Long-Run Forecast Residential Retail Sales
Focusing on residential kWh sales, Figure 3.14 is the residential UPC growth plotted
against the EIA’s annual growth forecast of U.S. residential use per household growth.
The EIA’s forecast is from the 2020 Annual Energy Outlook. EIA’s forecast shows positive
UPC growth by the early 2030s, while Avista’s growth does not become positive until the
1,000
1,050
1,100
1,150
1,200
1,250
1,300
1,350
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2
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M
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Expected Case
High Growth Rate
Low Growth Rate
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 61 of 317
Chapter 3: Economic & Load Forecast

Avista Corp 2021 Electric IRP 3-19
early 2040s. The higher EIA forecast reflects a population shift to warmer-climate states
where air conditioning is typically required most of the year. In contrast, Avista’s forecast
of positive UPC growth in the 2040s reflects the impact of the growth of EVs in the region.

Figure 3.14: UPC Growth Forecast Comparison to EIA

Figure 3.15 shows the EIA and the residential load growth forecasts. Avista’s forecast is
typically higher in the 2021-2028 period, reflecting an assumption that service area
population growth will exceed the U.S. average; this is consistent with government and
IHS forecasts for the far west and Rocky Mountain regions where Avista’s service territory
is located.

Figure 3.15: Load Growth Comparison to EIA

-1.0%
-0.5%
0.0%
0.5%
1.0%
1.5%
2.0%
20
2
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EIA Refrence Case Use Per Household Growth
UPC Growth, Residential Expected Case
-2.0%
-1.5%
-1.0%
-0.5%
0.0%
0.5%
1.0%
1.5%
2.0%
20
2
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EIA Purchased Residential Electricity Growth (Quad. BTU)
Load Growth, Residential Expected Case
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 62 of 317
Chapter 3: Economic & Load Forecast

Avista Corp 2021 Electric IRP 3-20
Energy Forecast and Climate Change Scenarios
In addition to the base-line forecast discussed above, Avista also developed a climate
change scenario. This scenario assumes the 20-year moving average (MA) trend is the
definition of normal weather under the Expected Case shown above in Figure 3.13.
Trending the moving average used two different approaches. The first approach relies on
HDD and CDD data for Avista’s service territory while the second relied on state-level
HDD and CDD forecasts from the Northwest Power and Conservation Council (NPCC).

The first approach applies the long-run time-series trend observed in the historical 20-
year MA for HDD and CDD. This historical trend shows HDD gradually declining and CDD
gradually increasing. Therefore, this trend is projected forward to produce a trended
moving average out to 2045. In Table 3.5, and Figures 3.16 and 3.17, this approach is
called, “Avista Trended 20-yr MA.” The exact analytical approach is provided in Appendix
K.

The second approach was to use the trend in the annual HDD and CDD forecasts
provided by the NPCC. These forecasts reflect recent NPCC efforts to model regional
climate impacts at the state level. Since Avista serves both Washington and Idaho, the
NPCC’s HDD and CDD forecasts for Washington and Idaho are averaged for each year
out to 2045 and then converted to a 20-year MA. This moving average is used as the
basis for establishing the long-run trend in HDD and CDD. This approach is called, “NPCC
Trended 20-yr MA.”

Table 3.5 and Figure 3.16 show how climate change impacts the Expected Case for
energy relative to the fixed 20-year MA. The climate effects are built-in after 2025, the
end year of the intermediate term forecast. With load shifting from winter to summer,
overall load levels and load growth are predicted to be lower with climate change. This
reflects the net impact of declining HDD and increasing CDD over the forecast horizon.
In addition, the difference between the Avista Trended Weather and the NPCC Trended
weather forecasts reflects a much more aggressive warming trend than Avista’s own
historical weather data indicates. Figure 3.17 shows how the different methods shift the
share of retail load across the months compared to the load shares of the fixed 20-year
MA—that is, without trended weather. Both the Avista and NPCC trended weather show
a shifting of load activity from winter to summer by 2045.

Table 3.5: Load Growth for Climate Scenarios (2026-2045)

Climate Scenario Average Annual Native Load
Growth
(percent)
Compared to Expected Case
Fixed 20-yr MA 0.23 -
Avista Trended 20-yr MA 0.21 4
NPCC Trended 20-yr MA 0.13 23

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 63 of 317
Chapter 3: Economic & Load Forecast

Avista Corp 2021 Electric IRP 3-21
Figure 3.16: Average Megawatts with Climate Scenarios

Figure 3.17: Load Share Comparison with Climate Scenarios

1,080
1,090
1,100
1,110
1,120
1,130
1,140
1,150
1,160
1,170
1,180
20
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4
3
20
4
4
20
4
5
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
2021 Expected Case, Fixed 20-yr MA
2021 Expected Case, Avista Trended 20-yr MA
2021 Expected Case, NPCC Trended 20-yr MA
7.0%
7.5%
8.0%
8.5%
9.0%
9.5%
10.0%
10.5%
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Mo
n
t
h
l
y

K
H
W

L
o
a
d

S
h
a
r
e
Without Trended Weather
2045, Avista Trended Weather
2045, NPCC Trended Weather
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 64 of 317
Chapter 3: Economic & Load Forecast

Avista Corp 2021 Electric IRP 3-22
Monthly Peak Load Forecast Methodology

The Peak Load Regression Model
The peak load hour forecast is used to determine the amount of resources necessary to
meet system peak demand. Avista must build generation capacity to meet winter and
summer peak periods. Looking forward, the highest peak loads are still most likely to
occur in the winter months, although in some years a mild winter followed by a hot
summer could find the annual maximum peak load occurring in a summer hour. Equation
3.5 shows the current peak load regression model.

Equation 3.5: Peak Load Regression Model

ℎ𝑀𝑊H,H,H
HHHHHHH= 𝜆H + 𝜆H𝐻𝐷𝐷H,H,H+ 𝜆H(𝐻𝐷𝐷H,H,H)H
+ 𝜆H𝐻𝐷𝐷HHH,H,H+ 𝜆H𝐶𝐷𝐷H,H,H + 𝜆H𝐶𝐷𝐷H,H,HHHHH+ 𝜆H𝐶𝐷𝐷HHH,H,H+ 𝜙H𝐺𝐷𝑃H.HHH
+ 𝜙H(𝐷HHH,HHHH↑∗ 𝐺𝐷𝑃H.HHH) + 𝜔HH𝐷H,H,H+ 𝜔HH𝐷H,H+ 𝜔HH𝐷HHH HHHHHH
+ 𝜖H,H,H 𝑓𝑜𝑟 𝑡,𝑦 = 𝐽𝑢𝑛𝑒 2004 ↑

Where:
 hMWH,H,H
HHHHHHH = metered peak hourly usage on day of week d, in month t, in
year y, and excludes two large industrial producers. The data series starts
in June 2004.
 HDDH,H,H and CDDH,H,H = heating and cooling degree days the day before the
peak.
 (HDDH,H,H)H = squared value of HDDd,t,y.HDDHHH,H,H and CDDHHH,H,H = heating
and cooling degree days the day before the peak.
 CDDH,H,HHHHH = maximum peak day temperature minus 65 degrees.16
 GDPH.HHH = extrapolated level of real GDP in month t in year y-1.
 (𝐷HHH,HHHH↑∗ 𝐺𝐷𝑃H.HHH) is a slope shift variable for GDP in the summer
months, June, July, and August.
 ωWDDd,t,y = dummy vector indicating the peak’s day of week.
 ωSDDt,y = seasonal dummy vector indicating the month; and the other
dummy variable control for an extreme outliers in March 2005.
 εd,t,y = uncorrelated N(0, σ) error term.

Generating Weather Normal Growth Rates Based on a GDP Driver
Equation 3.5 coefficients identify the month and day most likely to result in a peak load in
the winter or summer. By assuming normal peak weather and switching on the dummy
variables for day (dMAX) and month (tMAX) that maximize weather normal peak conditions
in winter and summer, a series of peak forecasts from the current year, yc, are generated
out N years by using forecasted levels of GDP as shown in Equation 3.5.17 All other

16 This term provides a better model fit than the square of CDD.
17 Forecasted GDP is generated by applying the averaged GDP growth forecasts used for the employment and
industrial production forecasts discussed previously.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 65 of 317
Chapter 3: Economic & Load Forecast

Avista Corp 2021 Electric IRP 3-23
factors besides GDP remain constant to determine the impact of GDP on peak load. For
winter, this is defined as the forecasted series W:

𝑊 = {𝐹(ℎ𝑀𝑊H ,H ,H HH
HH,HHHHHHH,H),𝐹(ℎ𝑀𝑊H ,H ,H HH
HH,HHHHHHH,H),…,𝐹(ℎ𝑀𝑊H ,H ,H HH
HH,HHHHHHH,H)}

For summer, this is defined as the forecasted series S:

𝑆 = {𝐹(ℎ𝑀𝑊H ,H ,H HH
HH,HHHHHHH,H),𝐹(ℎ𝑀𝑊H ,H ,H HH
HH,HHHHHHH,H),…,𝐹(ℎ𝑀𝑊H ,H ,H HH
HH,HHH HHHH,H)}

Both S and W are convertible to a series of annual growth rates, GhMW. Peak load growth
forecast equations are shown below as winter (WG) and summer (SG.):

𝑊H = {𝐹(𝐺ℎ𝑀𝑊H ,H ,H HH
HH,HHHHHHH,H),𝐹(𝐺ℎ𝑀𝑊H ,H ,H HH
HH,HHHHHHH,H),…,𝐹(𝐺ℎ𝑀𝑊H ,H ,H HH
HH,HHHHHHH,H)}

𝑆H = {𝐹(𝐺ℎ𝑀𝑊H ,H ,H HH
HH,HHHHHHH,H),𝐹(𝐺ℎ𝑀𝑊H ,H ,H HH
HH,HHHHHHH,H),…,𝐹(𝐺ℎ𝑀𝑊H ,H ,H HH
HH,HHHHHHH,H) }

Simulated Extreme Weather Conditions with Historical Weather Data
In Equation 3.6, holding all else constant, growth rates are applied to simulated peak
loads generated for the current year, yc, for each month, January through December.
These peak loads are generated by running actual extreme weather days observed since
1890. Equations 3.6 and 3.7 generate a series of simulated extreme peak load values for
heating degree days and cooling degree days respectively.

Equation 3.6: Peak Load Simulation Equation for Winter Months

ℎ𝑀𝑊H,HH= 𝑎 + 𝜆H𝐻𝐷𝐷H,H,HHH + 𝜆H(𝐻𝐷𝐷H,H,HHH )H 𝑓𝑜𝑟 𝑡 = 𝐽𝑎𝑛,…,𝐷𝑒𝑐 𝑖𝑓 𝑚𝑎𝑥𝑖𝑢𝑚 𝑎𝑣𝑔.𝑡𝑒𝑚𝑝
< 65 𝑎𝑛𝑑 𝑦 = 1890,…,𝑦H

Where:
 hMWH,HH = simulated winter peak megawatt load using historical weather
data.
 HDDt,y,MIN = heating degree days calculated from the minimum (MIN)
average temperature (average of daily high and low) on day d, in month t,
in year y if in month t the maximum average temperature (average of daily
high and low) is less than 65 degrees.
 a = aggregate impact of all the other variables held constant at their
average values.

Similarly, the model for cooling degree days is:

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 66 of 317
Chapter 3: Economic & Load Forecast

Avista Corp 2021 Electric IRP 3-24
Equation 3.7: Peak Load Simulation Equation for Summer Months

ℎ𝑀𝑊H,HH= 𝑎 + 𝜆H𝐶𝐷𝐷H,H,HHH 𝑓𝑜𝑟 𝑡 = 𝐽𝑎𝑛,…,𝐷𝑒𝑐 𝑖𝑓 𝑚𝑎𝑥𝑖𝑢𝑚 𝑎𝑣𝑔. 𝑡𝑒𝑚𝑝 > 65 𝑎𝑛𝑑 𝑦
= 1890,…,𝑦H

Where:
 hMWH,HH = simulated winter peak megawatt load using historical weather
data.
 CDDt,y,MAX = cooling degree days calculated from the maximum (MAX)
average temperature. The average of daily high (H) and low (L) on day d,
in month t, in year y if in month t if the maximum average temperature
(average of daily high and low) is greater than 65 degrees.
 a = aggregate impact of all the other variables held constant at their average
values.

With over 100 years of average maximum and minimum temperature data, Equations 3.6
and 3.7 applied to each month t will produce over 100 simulated values of peak load that
can be averaged to generate a forecasted average peak load for month t in the current
year, yc. Equations 3.8 and 3.9 show the average for each month.

Equation 3.8: Current Year Peak Load for Winter Months

𝐹ℎ𝑀𝑊H,HH =1
(𝑦H − 1890)+ 1 ℎ𝑀𝑊H,HH
H
HHHHHH
𝑓𝑜𝑟 𝑒𝑎𝑐ℎ ℎ𝑒𝑎𝑡𝑖𝑛𝑔 𝑚𝑜𝑛𝑡ℎ 𝑡
𝑤ℎ𝑒𝑟𝑒 𝑚𝑎𝑥𝑖𝑢𝑚 𝑎𝑣𝑔.𝑡𝑒𝑚𝑝 < 65

Equation 3.9: Current Year Peak Load for Summer Months

𝐹ℎ𝑀𝑊H,HH =1
(𝑦H− 1890)+ 1 ℎ𝑀𝑊H,HHH
HHHH
𝑓𝑜𝑟 𝑒𝑎𝑐ℎ 𝑐𝑜𝑜𝑙𝑖𝑛𝑔 𝑚𝑜𝑛𝑡ℎ 𝑡
𝑤ℎ𝑒𝑟𝑒 𝑚𝑎𝑥𝑖𝑢𝑚 𝑎𝑣𝑔.𝑡𝑒𝑚𝑝 > 65

Forecasts beyond yc are generated using the appropriate growth rate from series WG and
SG. For example, the forecasts for yc+1 for winter and summer are:

𝐹ℎ𝑀𝑊H,H
HH,HHHHHHH,H = 𝐹ℎ𝑀𝑊H,HH ∗ [1 + 𝐹(𝐺ℎ𝑀𝑊H ,H ,H HH
HH,HHHHHHH,H)]

𝐹ℎ𝑀𝑊H,H
HH,HHHHHHH,H = 𝐹ℎ𝑀𝑊H,HH ∗ [1 + 𝐹(𝐺ℎ𝑀𝑊H ,H ,H HH
HH,HHHHHHH,H)]

The finalization of the peak load forecast occurs when the forecasted peak loads of two
large industrial customers and EVs, excluded from the Equation 3.8 and 3.9 estimations,
are added back in.

Table 3.6 shows estimated peak load growth rates with and without the two large
industrial customers. Figure 3.17 shows the forecasted time path of peak load out to 2045,
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 67 of 317
Chapter 3: Economic & Load Forecast

Avista Corp 2021 Electric IRP 3-25
and Figure 3.18 shows the high/low bounds based on a 1-in-20 event (95 percent
confidence interval) using the standard deviation of the simulated peak loads from
Equations 3.8 and 3.9.

Table 3.6: Forecasted Winter and Summer Peak Growth, 2021-2045

Peak Load Annual Growth Winter
(Percent)
Summer
(Percent)
Including Large Industrial Customers 0.35 0.42

Figure 3.18 shows how the summer peak forecast grows faster than the winter peak.
Under current growth forecasts, the orange summer line in Figure 3.17 will get close to
the blue winter line by 2045. Figure 3.19 shows that the winter high/low bounds
considerably larger than summer and reflects a greater range of temperature anomalies
in the winter months.

Figure 3.18: Peak Load Forecast 2021-2045

1,000
1,100
1,200
1,300
1,400
1,500
1,600
1,700
1,800
1,900
2,000
19
9
7
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
20
1
3
20
1
5
20
1
7
20
1
9
20
2
1
20
2
3
20
2
5
20
2
7
20
2
9
20
3
1
20
3
3
20
3
5
20
3
7
20
3
9
20
4
1
20
4
3
20
4
5
Me
g
a
w
a
t
t
s
Winter Peak
Summer Peak
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 68 of 317
Chapter 3: Economic & Load Forecast

Avista Corp 2021 Electric IRP 3-26
Figure 3.19: Peak Load Forecast with 1 in 20 High/Low Bounds, 2021-2045

Peak Load Forecast and Climate Change
To simulate the impact of climate change on the peak load, the Expected Case’s forecast
assumes Avista Trended Weather as the basis for the forecast. The impact is shown in
Table 3.7 and Figures 3.20, 3.21 and 3.22.

Table 3.7: Forecasted Winter and Summer Peak
Growth with Trended Climate, 2021-2045

Peak Load Annual Growth Winter Summer
Avista Trended 20-yr MA, Including Large Industrial Customers 0.32 0.47
NPCC Trended 20-yr MA, Including Large Industrial Customers 0.22 0.53

Using the Avista trended weather lowers the winter growth rate and increases the summer
growth rate. In addition, the level of peak-load starting in 2021 is lower in the winter and
higher in the summer. The combined result is a shift from a winter peaking to a summer
peaking by the early 2030s. However, Figure 3.21 shows that because of the distribution
of possible winter temperatures relative to summer, the 1-in-20 high range still exceeds
summer loads. This relationship changes notably with the NPCC Trended Weather as the
basis for the forecast as shown in Figure 3.22. This figure shows Avista becomes summer
peaking by the late 2020s and by the 2040s, the high range for summer exceeds winter’s
peak. The difference between the winter and summer growth rates also increases with
NPCC trended weather.

1,000
1,200
1,400
1,600
1,800
2,000
2,200
19
9
7
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
20
1
3
20
1
5
20
1
7
20
1
9
20
2
1
20
2
3
20
2
5
20
2
7
20
2
9
20
3
1
20
3
3
20
3
5
20
3
7
20
3
9
20
4
1
20
4
3
20
4
5
Me
g
a
w
a
t
t
s
Winter Peak Summer Peak
Winter- High Winter- Low
Summer- High Summer- Low
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 69 of 317
Chapter 3: Economic & Load Forecast

Avista Corp 2021 Electric IRP 3-27
Figure 3.20: Peak Load Forecast with Avista Trended 20-yr MA, 2021-2045

Figure 3.21: Peak Load Forecast with 1-in-20 High/Low Bounds and
Avista Trended 20-yr MA, 2021-2045

1,000
1,100
1,200
1,300
1,400
1,500
1,600
1,700
1,800
1,900
2,000
19
9
7
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
20
1
3
20
1
5
20
1
7
20
1
9
20
2
1
20
2
3
20
2
5
20
2
7
20
2
9
20
3
1
20
3
3
20
3
5
20
3
7
20
3
9
20
4
1
20
4
3
20
4
5
Me
g
a
w
a
t
t
s
Winter Peak
Summer Peak
1,000
1,200
1,400
1,600
1,800
2,000
2,200
19
9
7
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
20
1
3
20
1
5
20
1
7
20
1
9
20
2
1
20
2
3
20
2
5
20
2
7
20
2
9
20
3
1
20
3
3
20
3
5
20
3
7
20
3
9
20
4
1
20
4
3
20
4
5
Me
g
a
w
a
t
t
s
Winter Peak Summer Peak
Winter- High Winter- Low
Summer- High Summer- Low
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 70 of 317
Chapter 3: Economic & Load Forecast

Avista Corp 2021 Electric IRP 3-28
Figure 3.22: Peak Load Forecast with 1 in 20 High/Low Bounds and
NPCC Trended 20-yr MA, 2021-2045

1,000
1,200
1,400
1,600
1,800
2,000
2,200
19
9
7
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
20
1
3
20
1
5
20
1
7
20
1
9
20
2
1
20
2
3
20
2
5
20
2
7
20
2
9
20
3
1
20
3
3
20
3
5
20
3
7
20
3
9
20
4
1
20
4
3
20
4
5
Me
g
a
w
a
t
t
s
Winter Peak Summer Peak
Winter- High Winter- Low
Summer- High Summer- Low
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 71 of 317
Chapter 3: Economic & Load Forecast

Avista Corp 2021 Electric IRP 3-29
Table 3.8: Energy and Peak Forecasts

Year Energy
(aMW) January July
2021 1,097 1,712 1,616
2022 1,102 1,719 1,626
2023 1,107 1,725 1,633
2024 1,107 1,729 1,638
2025 1,115 1,733 1,643
2026 1,117 1,738 1,648
2027 1,119 1,742 1,653
2028 1,122 1,746 1,659
2029 1,124 1,751 1,664
2030 1,125 1,756 1,670
2031 1,127 1,761 1,676
2032 1,129 1,766 1,682
2033 1,130 1,771 1,688
2034 1,132 1,777 1,695
2035 1,133 1,783 1,702
2036 1,135 1,789 1,710
2037 1,137 1,796 1,718
2038 1,139 1,804 1,726
2039 1,142 1,812 1,735
2040 1,144 1,821 1,745
2041 1,148 1,830 1,756
2042 1,151 1,841 1,768
2043 1,155 1,853 1,781
2044 1,160 1,867 1,795
2045 1,166 1,882 1,811

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 72 of 317
Chapter 3: Economic & Load Forecast

Avista Corp 2021 Electric IRP 3-30

This Page Intentionally Left Blank

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 73 of 317
Chapter 4: Existing Supply Resources
Avista Corp 2021 Electric IRP 4-1
4. Existing Supply Resources

Avista relies on a diverse portfolio of assets to meet customer loads, including owning
and operating eight hydroelectric developments on the Spokane and Clark Fork rivers. Its
thermal assets include ownership of five natural gas-fired projects, a biomass plant, and
partial ownership of two coal-fired units. Avista also purchases energy from several
independent power producers (IPPs) and regional utilities.

Figure 4.1 shows Avista’s capacity and energy mixes. Winter capability is the share of
total capability of each resource type the utility can rely upon to meet winter peak load.
The annual energy chart represents the energy as a percent of total supply; this
calculation includes fuel limitations (for water, wind, and wood), maintenance and forced
outages. Avista’s largest energy supply in the peak winter months is from hydro at 50
percent, followed by natural gas-fired resources at 36 percent. On an annual basis,
natural gas-fired generation can produce more energy (40 percent) than hydroelectric (36
percent) because it is not constrained by fuel limitations. The resource mix changes each
year depending on streamflow conditions and market prices.

Figure 4.1: 2020 Avista Capability and Energy Fuel Mix

Section Highlights
 Hydro represents about half of Avista’s winter generating capability.
 Natural gas-fired plants represent the largest portion of Avista’s thermal
generation portfolio.
 The Rattlesnake Flat wind facility began operations in December 2020.
 Fifty-five percent of Avista’s generating potential is hydro, biomass, wind, and
solar.
 Avista’s net metering program includes 1,345 customers with 14.1 megawatts
of their own generation.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 74 of 317
Chapter 4: Existing Supply Resources
Avista Corp 2021 Electric IRP 4-2
Avista reports its fuel mix annually in the Washington State Fuel Mix Disclosure1. The
State calculates the resource mix used to serve load, rather than generation potential, by
adding regional2 estimates for unassigned market purchases and Avista-owned
generation minus net renewable energy credit (REC) sales3. Figure 4.2 shows Avista’s
2019 fuel mix disclosure from the Washington State Department of Commerce. The Idaho
fuel mix is nearly identical to Washington except for its allocation of PURPA generation.
Each state receives RECs based on their share of the system (approximately 65 percent
Washington and 35 percent Idaho). Avista may retain RECs, sell them to other parties or
transfer them between states. Avista transfers RECs from Idaho to help comply with
Washington’s Energy Independence Act (EIA). Idaho customers are compensated for the
value of RECs at market value.

Figure 4.2: 2019 Washington State Fuel Mix Disclosure

Spokane River Hydroelectric Developments
Avista owns and operates six hydroelectric developments on the Spokane River. Five
operate under a 50-year FERC operating license through June 18, 2059. The sixth, Little
Falls, operates under separate authorization from the U.S. Congress4. This section
describes the Spokane River developments and provides the maximum on-peak and
nameplate capacity ratings for each plant. The maximum on-peak capacity of a
generating unit is the total amount of electricity it can safely generate with its existing
configuration and the current mechanical state of the facility. Unlike other generation
assets, hydro capacity is often higher than nameplate because of plant upgrades and
favorable head or streamflow conditions. The nameplate, or installed capacity, is the

1 Report 11-A Utility Fuel Mix Market Summary – 20200911 post adjust.pdf from Department of
Commerce.
2 For 2019, the region is approximately 54 percent hydroelectric, 13 percent unspecified, 12 percent natural
gas, 11 percent coal, 5 percent nuclear, 4 percent wind and 1 percent other. When Avista sells RECs from
its resources they are assigned an emissions level in the report equal to regional average emissions.
3 In 2019, Avista sold 44 aMW of RECs, which lowers the percentage of renewable resources.
4 Little Falls is not under FERC jurisdiction as it was congressionally authorized because of its location on
the Spokane Indian Reservation. Avista operates Little Falls Dam in accordance with an agreement reached
with the Tribe in 1994 to identify operational and natural resource requirements. Little Falls Dam is also
subject to other Washington State environmental and dam safety requirements.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 75 of 317
Chapter 4: Existing Supply Resources
Avista Corp 2021 Electric IRP 4-3
capacity of a plant as rated by the manufacturer. All six hydroelectric developments on
the Spokane River connect directly to the Avista electrical system.

Post Falls
Post Falls is the hydroelectric facility furthest upstream on the Spokane River. It is located
several miles east of the Washington/Idaho border. The facility began operating in 1906
and during summer months maintains the elevation of Lake Coeur d’Alene. Post Falls
has a 14.75 MW nameplate rating and is capable of producing up to 18.0 MW with its six
generating units.

Upper Falls
The Upper Falls development sits within the boundaries of Riverfront Park in downtown
Spokane. It began generating in 1922. The project is comprised of a single 10.0 MW unit.

Monroe Street
Monroe Street was Avista’s first generation development. It began serving customers in
1890 in downtown Spokane near Riverfront Park. Following a complete rehabilitation in
1992, the single generating unit has a 15.0 MW maximum capacity rating.

Nine Mile
A private developer built the Nine Mile development in 1908 near Nine Mile Falls,
Washington. Avista purchased the project in 1925 from the Spokane & Inland Empire
Railroad Company. Nine Mile has undergone recent substantial upgrades. The
development has two new 8 MW units and two 10 MW units for a total nameplate rating
of 36 MW. The incremental generation from the upgrades qualifies for Washington’s EIA.

Long Lake
The Long Lake development is located northwest of Spokane and maintains the Lake
Spokane reservoir, also known as Long Lake. The project’s four units have a nameplate
rating of 81.6 MW and 88.0 MW of combined capacity. Chapter 9, Supply-Side Resource
Options, provides modernization options under consideration at Long Lake.

Little Falls
The Little Falls development, completed in 1910 near Ford, Washington, is the furthest
downstream hydroelectric facility on the Spokane River. The facility’s four units generate
35.2 MW.

Clark Fork River Hydroelectric Development
The Clark Fork River Development includes hydroelectric projects located near Clark
Fork, Idaho, and Noxon, Montana, 70 miles south of the Canadian border on the Clark
Fork River. The plants operate under a FERC license through 2046 and connect directly
to the Avista transmission system.

Noxon Rapids
The Noxon Rapids development includes four generators installed between 1959 and
1960, and a fifth unit that entered service in 1977. Avista completed major turbine
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upgrades on units 1 through 4 between 2009 and 2012. The upgrades increased the
capacity of each unit from 105 MW to 112.5 MW and added 6.6 aMW of additional energy.
The total capability of the plant is 610 MW.

Cabinet Gorge
Cabinet Gorge started generating power in 1952 with two units, and two additional
generators were added the following year. Upgrades to units 1 through 4 occurred in
1994, 2004, 2001 and 2007, respectively. The current maximum on-peak plant capacity
is 270.5 MW, modestly above its 265.2 MW nameplate. The incremental generation from
the upgrades qualifies for the EIA. Chapter 9, Supply-Side Resource Options, provides
modernization options under consideration at Cabinet Gorge.

Total Hydroelectric Generation
In total, Avista’s hydroelectric plants have 1,080 MW of capacity. Table 4.1 summarizes
the location and operational capacities of Avista’s hydroelectric projects, and the
expected energy output of each facility based on an 80-year hydrologic record.

Table 4.1: Avista-Owned Hydroelectric Resources

Project Name River
System
Location Nameplate
Capacity

Maximum
Capability

Expected
Energy

Monroe Street Spokane Spokane, WA 14.8 15.0 11.2
Post Falls Spokane Post Falls, ID 14.8 18.0 9.4
Nine Mile Spokane Nine Mile Falls, WA 36.0 32.0 15.7
Little Falls Spokane Ford, WA 32.0 35.2 22.6
Long Lake Spokane Ford, WA 81.6 89.0 56.0
Upper Falls Spokane Spokane, WA 10.0 10.2 7.3

Noxon Rapids Clark Fork Noxon, MT 518.0 610.0 196.5
Cabinet Gorge Clark Fork Clark Fork, ID 265.2 270.5 123.6

Thermal Resources
Avista owns seven thermal generation assets located across the Northwest. These assets
provide dependable energy and capacity serving base and peak-load obligations. Table
4.2 summarizes these resources by fuel type, online year, remaining design life, book
value at the end of 2019 and remaining accounting life. Appendix D provides operating
details for these facilities between 2016 and 2020. Table 4.3 includes capacity information
for each of the facilities along with the five-year historical forced outage rates used for
modeling purposes. Plants with a number in parentheses indicates the number of equally
sized units at each facility.

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Table 4.2: Avista-Owned Thermal Resources

Project Name Location Fuel Start Remaining Book Value Book Life
Colstrip 3 & 4 Colstrip, MT Coal 19845 25 97.2 See Note6
Rathdrum Rathdrum, ID Gas 1995 40 34.2 11
Northeast Spokane, WA Gas 1978 15 0.2 5
Boulder Park Spokane, WA Gas 2002 20 16.0 18
Coyote Springs 2 Boardman, OR Gas 2003 25 117.2 19
Kettle Falls Kettle Falls, WA Wood 1983 20 53.1 11
Kettle Falls CT Kettle Falls, WA Gas 2002 40 3.3 12

Table 4.3: Avista-Owned Thermal Resource Capability

Project Name Winter
Maximum
Summer
Maximum
Nameplate
Capacity (MW)
Forced
Outage Rate
Colstrip 3 111 111 123.5 9.3
Colstrip 4 111 111 123.5 9.3
Rathdrum (2 units) 176 130 166.2 5.0
Northeast (2 units) 66 42 61.8 5.0
Boulder Park (6 units) 24.6 24.6 24.6 13.7
Coyote Springs 2 317.5 286 306.5 2.6
Kettle Falls 47 47 50.7 2.4
Kettle Falls CT 11 8 7.2 5.0

Colstrip Units 3 and 4
The Colstrip plant, located in eastern Montana, consists of the two remaining coal-fired
steam plants connected to a double-circuit 500 kV line owned by each of the participating
utilities. The utility-owned segment extends from Colstrip to Townsend, Montana. BPA’s
ownership of the 500 kV line starts in Townsend and continues west. Energy moves
across both segments of the transmission line under a long-term wheeling arrangement.
Talen Energy Corporation operates the facilities on behalf of the six owners. Avista owns
15 percent of Units 3 and 4. Unit 3 began operating in 1984 and Unit 4 was finished in
1986. Avista’s share of Colstrip has a maximum net capacity of 222 MW, and a nameplate
rating of 247 MW.

Rathdrum
Rathdrum consists of two identical simple-cycle combustion turbine (CT) units. This
natural gas-fired plant located near Rathdrum, Idaho connects to the Avista transmission
system. It entered service in 1995 and has a maximum combined capacity of 176 MW in
the winter and 126 MW in the summer. The nameplate rating is 166.5 MW. Chapter 9,
Supply-Side Resource Options, provides details about modernization options under
consideration at Rathdrum.

5 Colstrip unit 3 began in 1984 and Colstrip 4 began in 1986.
6 Avista is modeling Colstrip Units 3 and 4 with a depreciable life ending in 2025 in Washington and 2027
in Idaho, as approved by the Washington and Idaho Commissions.
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Northeast
The Northeast plant, located in Spokane, has two identical aero-derivative simple-cycle
CT units completed in 1978. It connects to Avista’s transmission system. The plant is
capable of burning natural gas, but current air permits preclude the use of fuel oil. The
combined maximum capacity of the units is 68 MW in the winter and 42 MW in the
summer, with a nameplate rating of 61.2 MW. The plant air permit limits run hours to 100
hours per year, limiting its use primarily to reliability events. Avista assumes this plant will
retire in 2035 for modeling purposes of this IRP.

Boulder Park
The Boulder Park project entered service in the Spokane Valley in 2002. It connects
directly to the Avista transmission system. The site uses six identical natural gas-fired
internal combustion reciprocating engines to produce a combined maximum capacity and
nameplate rating of 24.6 MW. Avista assumes this plant will retire in 2040 for modeling
purposes of this IRP.

Coyote Springs 2
Coyote Springs 2 is a natural gas-fired combined cycle combustion turbine (CCCT)
located near Boardman, Oregon. The plant connects to the BPA 500 kV transmission
system under a long-term agreement. The plant began service in 2003 and has a
maximum capacity of 317.5 MW in the winter and 285 MW in the summer with duct
burners operating. The nameplate rating of the plant is 287.3 MW.

Kettle Falls Generation Station and Kettle Falls Combustion Turbine
The Kettle Falls Generating Station entered service in 1983 near Kettle Falls,
Washington. It is among the largest biomass generation plants in North America and
connects to Avista on its 115 kV transmission system. The open-loop steam plant uses
waste wood products (hog fuel) from area mills and forest slash but can also burn natural
gas on a limited basis. A 7.5 MW combustion turbine (CT), added to the facility in 2002,
burns natural gas and increases overall plant efficiency by sending exhaust heat to the
wood boiler when operating in combined-cycle mode.

The wood-fired portion of the plant has a maximum capacity of 50 MW and a nameplate
rating of 50.7 MW. Varying fuel moisture conditions at the plant causes correlated
variation between 45 and 50 MW. The plant’s capacity increases from 55 to 58 MW when
operated in combined-cycle mode with the CT. The CT produces 8 MW of peaking
capability in the summer and 11 MW in the winter. The CT can be limited in the winter
when the natural gas pipeline is capacity constrained. The CT is not available when
temperatures fall below zero7. This operational assumption reflects natural gas availability
limits in the area. Chapter 9, Supply-Side Resource Options, provides details about
modernization options under consideration at Kettle Falls.

7 Avista is reviewing its policies and may restrict the CT use when the pipeline is at lower pressures then
the current standard. This change could further restrict the plant from producing power in winter months.
For this IRP, Avista assumes no winter Kettle Falls CT capacity after 2023.
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Small Avista-Owned Solar
Avista operates three small solar projects. The first solar project is three kilowatts located
on its corporate headquarters as part of its Solar Car initiative. Avista installed a 15
kilowatt solar system in Rathdrum, Idaho to supply its My Clean Energy™ (formerly Buck-
A-Block) voluntary green energy program. The 423-kW Avista Community Solar project,
located at the Boulder Park property, began service in 2015.

Table 4.4: Avista-Owned Solar Resource Capability

Project Name Project Location Project Capacity
(kW-DC)
Spokane Headquarters Solar Spokane, WA 3
Rathdrum Solar Rathdrum, ID 15
Boulder Park Solar Spokane Valley, WA 423
Total 441

Power Purchase and Sale Contracts
Avista uses purchase and sale arrangements of varying lengths to meet a portion of its
load requirements. These contracts provide many benefits by including environmentally
low-impact from low-cost hydro and wind power to the Company’s resource mix. This
chapter describes the contracts in effect during the timeframe of the 2021 IRP. Tables 4.4
through 4.6 summarize Avista’s contracts.

Mid-Columbia Hydroelectric Contracts
During the 1950s and 1960s, Public Utility Districts (PUDs) in central Washington
developed hydroelectric projects on the Columbia River. Each plant was large compared
to loads served by the PUDs. Long-term contracts with public, municipal and investor-
owned utilities throughout the Northwest assisted with project financing by providing a
market for the surplus power. The contract terms obligate the PUDs to deliver power to
Avista points of interconnection.

Avista originally entered into long-term contracts for the output of five projects “at cost”.
Avista now competes in capacity auctions to retain the rights of these contracts as they
expire. The Mid-Columbia contracts in Table 4.5 provide clean energy, capacity and
reserve capabilities; in 2020, the contracts provided approximately 247 MW of capacity
and 148 aMW of energy.

The timing of the power received from the Mid-Columbia projects is a result of agreements
including the 1961 Columbia River Treaty and the 1964 Pacific Northwest Coordination
Agreement (PNCA). Both agreements optimize hydroelectric project operations in the
Northwest U.S. and Canada. In return for these benefits, Canada receives return energy
under the Canadian Entitlement. The Columbia River Treaty and the PNCA manage
storage water in upstream reservoirs for coordinated flood control and power generation
optimization. The Columbia River Treaty may end on September 15, 2024. Studies are
underway by U.S. and Canadian entities to determine possible post-2024 Columbia River
operations. Federal agencies are soliciting feedback from stakeholders and ongoing
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negotiations will determine the future of the treaty. This IRP does not model alternative
outcomes for the treaty negotiations, because they likely will not affect long-term resource
acquisitions and this IRP does not speculate on future wholesale electricity market
impacts of the treaty at this time.

Table 4.5: Mid-Columbia Capacity and Energy Contracts8

Counter
Party
Project(s) Percent
Share
(%)
Start Date End Date 2020
Estimated
On-Peak
Capability
2020
Annual
Energy
(aMW)
Grant PUD Priest Rapids 3.79 Dec-2001 Dec-2052 30 19.5
Grant PUD Wanapum 3.79 Dec-2001 Dec-2052 32 18.7
Chelan PUD Rocky Reach 5.0 Jan-2016 Dec-2030 57 35.9
Chelan PUD Rock Island 5.0 Jan-2016 Dec-2030 19 18.4
Douglas PUD Wells 12.769 Oct-2018 Dec-2028 107 57.0
Canadian Entitlement -14 -5.6
2020 Total Net Contracted Capacity and Energy 230 143.9

Public Utility Regulatory Policies Act (PURPA)
The passage of PURPA by Congress in 1978 required utilities to purchase power from
resources meeting certain size and fuel criteria. Avista has many PURPA contracts, as
shown in Table 4.6. The IRP assumes renewal of these contracts after their current terms
end based on our experience with these contracts and ongoing communications with the
project owners. Appendix D includes operating details of these projects. Avista takes the
energy as produced, does not control the output of any PURPA resources and does not
receive the RECs from these projects.

Lancaster Power Purchase Agreement
Avista acquired output rights to the Lancaster CCCT, located in Rathdrum, Idaho, after
the sale of Avista Energy in 2007. Lancaster directly interconnects with the Avista
transmission system at the BPA Lancaster substation. Under the tolling contract, Avista
pays a monthly capacity payment for the sole right to dispatch the plant through October
2026. In addition, Avista pays a variable energy charge and arranges for all of the fuel
needs of the plant.

Palouse Wind Power Purchase Agreement
Avista signed a 30-year PPA in 2011 with Palouse Wind for the entire output of its 105
MW project starting in December 2012. Avista has the option to purchase the project after
2022. The project is EIA-qualified and directly connects to Avista’s transmission system
between Rosalia and Oaksdale, Washington in Whitman County.

8 For purposes of long-term transmission reservation planning for bundled retail service to native load
customers, replacement resources for each of the resources identified in Table 4.5 are presumed and
planned to be integrated via Avista’s interconnection(s) to the Mid-Columbia region.
9 Percent share varies each year depending on Douglas PUD’s load growth, although the 10 percent share
expires in 2023.
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Table 4.6: PURPA Agreements

Contract Fuel Source Location Contract
End Date
Size
(MW)
5 year
avg. Gen.
History
Meyers Falls Hydro Kettle Falls, WA 12/2025 1.30 1.10
Spokane Waste to Energy Waste Spokane, WA 12/2022 22.70 13.54
Spokane County Digester Biomass Spokane, WA 8/2021 0.26 0.13
Plummer Saw Mill Wood Waste Plummer, ID 12/2021 5.80 3.81
Deep Creek Hydro Northport, WA 12/2022 0.41 0.01
Clark Fork Hydro Hydro Clark Fork, ID 12/2037 0.22 0.13
Upriver Dam10 Hydro Spokane, WA 12/2024 14.50 5.16
Big Sheep Creek Hydro Hydro Northport, WA 6/2021 1.40 0.89
Ford Hydro LP Hydro Weippe, ID 6/2022 1.41 0.41
John Day Hydro Hydro Lucile, ID 9/2022 0.90 0.33
Phillips Ranch Hydro Northport, WA n/a 0.02 0.01
City of Cove Hydro Cove, OR 10/2038 0.80 0.28
Clearwater Paper Biomass Lewiston, ID 12/2023 90.20 51.68
Total 139.92 78.49

Rattlesnake Flat Wind Power Purchase Agreement
Between the 2017 and 2020 IRPs, Avista identified an opportunity to procure low-cost
wind energy at prices close to the energy market. This opportunity maintains Avista’s
lower power costs and assists in meeting CETA and corporate clean energy targets.
Rattlesnake Flat was selected as the preferred project in our 2018 request for proposals
(RFP) for 50 aMW of renewable energy. It is a 160.5 MW (limited to 144 MW) 20-year
PPA with an expected net output of 469,000 MWh (53.5 aMW) each year. Located east
of Lind, Washington in Adams County, the project went online in December 2020.

Adams-Nielson Solar Power Purchase Agreement
Avista signed a 20-year PPA for the Adams-Nielson solar project in 2017. The 80,000
panel, single axis, solar facility is capable of delivering 19.2 MW of alternating current
(AC) power entered service in December 2018. The project is located north of Lind,
Washington in Adams County. The project provides energy for Avista’s Solar Select
program. Solar Select allows commercial customers to voluntarily purchase solar energy
attributes from the project at no additional cost through a combination of tax incentives
from the State of Washington and offsetting power supply expenses.

Sales Contracts
Avista has intermediate power sales contracts used to optimize Avista’s energy position
on behalf of customers. Avista currently has three sales contracts extending through
2023. These contracts include Nichols Pumping, a sale of power at Colstrip; Douglas
PUD which is part of an exchange agreement tied to the 10 percent purchase of Wells
hydro project; and the Morgan Stanley contract to facilitate the sale of Clearwater Paper’s

10 Energy estimate is net of the City of Spokane’s pumping load.
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generation. For resource planning purposes, Avista does not assume contract sale
extensions.

Table 4.7: Other Contractual Rights and Obligations

Contract Type Fuel Source End
Date Capacity
Contri-
bution
Capacity
Contri-
bution
Energy
(aMW)
Lancaster Purchase Natural Gas 2026 283.0 231.0 218.0
Palouse Wind Purchase Wind 2042 5.3 5.3 36.2
Rattlesnake Flat Purchase Wind 2040 7.2 7.2 53.5
Adams-Nielson Purchase Solar 2038 0.4 10.2 5.6
Nichols Pumping Sale System 202311 -5.0 -5.0 -5.0
Morgan Stanley Sale Clearwater 2023 -46.0 -46.0 -44.9
Total 196.9 154.7 215.4

Customer-Owned Generation
Avista had 1,345 customer-installed net-metered generation projects on its system in
early December 2020, representing a total installed capacity of 14.1 MW direct current
(DC). Ninety-one percent of installations are in Washington; most are located in Spokane
County. Figure 4.3 shows annual net metering customer additions since 1999. Solar is
the primary net metered technology; the remaining are wind, combined solar and wind
systems, and biogas. The average size of the customer installations is 7.65 kilowatts.
Solar additions are falling due to the expiration of production incentives for new
installations in Washington prior to the end of 2020. In Idaho, solar installation rates
continue to increase each year without a major subsidy, but total only 117 customers
compared to Washington’s 1,200 plus customer installations. If net-metering customers
continue to increase, Avista may need to adjust rate structures for these customers. Much
of the cost of utility infrastructure to support reliable energy delivery is recovered in energy
rates. Net metering customers continue to benefit from this infrastructure but are no
longer purchasing as much energy, thereby transferring costs to customers not
generating their own power.

11 This obligation operates pumping loads in Colstrip. The end date reflects the energy sold to other Colstrip
participants, Avista’s obligation is approximately one megawatt and will end when Avista exits the plant.
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Figure 4.3: Avista’s Net Metering Customers

Natural Gas Pipeline Rights
Avista transports natural gas to its natural gas-fired generators using the GTN pipeline
owned by TC Energy (formally TransCanada). The pipeline runs between Alberta,
Canada and the California/Oregon border at Malin. Avista holds 60,592 dekatherms per
day of capacity from Alberta to Stanfield12, and another 26,388 dekatherms per day from
Stanfield to Malin. Figure 4.4 illustrates Avista’s natural gas pipeline rights. Also included
in this figure is the theoretical capacity if the plant runs at full capacity for the entire 24
hours in a day on the system. The maximum burn by Avista is 136,326 dekatherms in
one day based on the average of the top five historical natural gas burn days of 2019 and
2020, as shown in Table 4.8.

As discussed above, Avista does not have firm transportation rights for the entirety of its
natural gas generation capacity. Avista relies on short-term transportation contracts to
meet needs above our firm contractual rights. Adequate surplus transportation has
historically been available because the GTN pipeline was not fully subscribed. Natural
gas producers have recently purchased all remaining rights on the system to transport
their supply south and take advantage of higher prices in the U.S. compared to Canada.
However, these suppliers do not appear to have firm off-takers of their product, and
therefore a lack of transportation likely will not lead to a lack of fuel for our natural gas
plants. This becomes a pricing rather than a supply issue when suppliers control the
pipeline. Avista will continue acquiring natural gas delivery beyond our firm rights through
the daily market. When the market begins to tighten, or the premiums paid for delivery

12 Beginning on November 1, 2023, Avista will have transportation rights to 69,388 Dekatherms from Alberta
to the U.S. border (Kingsgate) to match its rights to Stanfield.
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through suppliers increases greatly, Avista will revisit its options. These options include
procurement through pipeline capacity expansions and investment in onsite fuel storage.

Figure 4.4: Avista Firm Natural Gas Pipeline Rights

Table 4.8: Top Five Historical Peak Natural Gas Usage (Dekatherms)

Date Boulder
Park Springs 2 Total Rights
3/2/2019 5,361 45,855 48,889 43,614 143,719 60,592
3/1/2019 4,641 44,585 47,340 43,298 139,864 60,592
4/12/2020 4,427 45,651 44,150 44,106 138,333 60,592
4/5/2020 4,555 45,629 43,505 43,357 137,046 60,592
4/8/2020 4,498 45,411 43,625 42,792 136,326 60,592

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Resource Environmental Requirements and Issues
Electricity generation creates environmental impacts subject to regulation by federal,
state and local authorities. The generation, transmission, distribution, service and storage
facilities Avista has ownership interests in are designed, operated and monitored to
maintain compliance with applicable environmental laws. Avista conducts periodic
reviews and audits of its facilities and operations to ensure continued compliance. To
respond to or anticipate emerging environmental issues, Avista monitors legislative and
regulatory developments at all levels of government for environmental issues, particularly
those with the potential to impact the operation and productivity of our generating plants
and other assets.

Generally, environmental laws and regulations have the following impacts while
maintaining and enhancing the environment:

 Increase operating costs of generation;
 Increase the time and costs to build new generation;
 Require modifications to existing plants;
 Require curtailment or retirement of generation plants;
 Reduce the generating capability of plants;
 Restrict the types of plants that can be built or contracted with;
 Require construction of specific types of generation at higher cost; and
 Increase the cost to transport and distribute natural gas.

The following sections describe applicable environmental regulations in more detail.

Clean Air Act (CAA)
The CAA is a federal law setting requirements for thermal generating plants. States are
typically authorized to implement CAA permitting and enforcement. States have adopted
parallel laws and regulations to implement the CAA. Some aspects of its implementation
are delegated to local air authorities. Colstrip, Coyote Springs 2, Kettle Falls and
Rathdrum CT all require CAA Title V operating permits. Boulder Park and the Northeast
CT require minor source permits or simple source registration permits to operate. These
requirements can change as the CAA or other regulations change and agencies review
and issue new permits. A number of specific regulatory programs authorized under the
CAA impact Avista’s generation, as reflected in the following sections.

Hazardous Air Pollutants (HAPs)
On April 16, 2016, the Mercury Air Toxic Standards (MATS), an EPA rule under the CAA
for coal and oil-fired sources, became effective for all Colstrip units. Colstrip performs
quarterly compliance assurance stack testing to meet the MATS site-wide limitation for
Particulate Matter (PM) emissions (0.03 lbs./MMBtu) a measure used as a surrogate for
all HAPs.

On May 22, 2020, EPA published its reconsideration of the “appropriate and necessary”
finding and concluded that it is not “appropriate and necessary” to regulate electric utility
steam generation units under section 112 of the CCA. EPA also took final action on the
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residual risk and technology review that is required by CAA section 112 and determined
that emissions from HAP have been reduced such that residual risk is at acceptable
levels. There are no developments in HAP emission controls to achieve further cost-
effective reductions beyond the current standards and, therefore, no changes to the
MATS rule are warranted.

Montana Mercury Rule
Montana established a site wide Mercury cap in 2010, requiring Mercury to be below 0.9
lbs. per trillion Btu. Colstrip installed a mercury oxidizer/sorbent injection system to
comply with the cap. The Montana Department of Environmental Quality (MDEQ) recently
reviewed the equipment and concurred with the plant’s assessment that units 3 and 4
operate at 0.8 lb. per Tbtu range. There is no indication mercury requirements will change
in the IRP time horizon.

Regional Haze Program
EPA set a national goal in 1999 to eliminate man-made visibility degradation in national
parks and wilderness areas by 2064. Individual states must take actions to make
“reasonable progress” through 10-year plans, including application of Best Available
Retrofit Technology (BART) requirements. BART is a retrofit program applied to large
emission sources, including electric generating units built between 1962 and 1977. In the
absence of state programs, EPA may adopt Federal Implementation Plans (FIPs). On
September 18, 2012, EPA finalized the Regional Haze FIP for Montana. In November
2012, several groups petitioned the U.S. Court of Appeals for the Ninth Circuit for review
of Montana’s FIP. The Court vacated portions of the Final Rule and remanded back to
EPA for further proceedings on June 9, 2015. MDEQ is in the process of retaking control
of the program from EPA after issuing a Regional Haze Program progress plan for
Montana in 2017 and Montana’s plan for the 2018 – 2028 period is expected to be
submitted to EPA by July 31, 2021. A combination of LoNOx burners, overfire air, and
SmartBurn currently control NOx emissions at Colstrip. Regional coal plant shutdowns
indicate the NOx emissions are below the glide path. This progress demonstrates
reasonable progress; therefore, Avista anticipates no additional NOx pollution controls
Colstrip at this time.

Coal Ash Management/Disposal
In 2015, EPA issued a final rule on coal combustion residuals (CCRs), also known as
coal combustion byproducts or coal ash. The rule has been subject to ongoing litigation.
In August 2018, the D.C. Circuit struck down provisions of the rule. The rule includes
technical requirements for CCR landfills and surface impoundments under Subtitle D of
the Resource Conservation and Recovery Act, the nation's primary law for regulating solid
waste. The Colstrip owners developed a multi-year compliance plan to address the CCR
requirements and existing state obligations expressed largely through a 2012
Administrative Order on Consent (AOC). These requirements continue despite the 2018
federal court ruling.

In addition, under the AOC, the Colstrip owners must provide financial assurance,
primarily in the form of surety bonds, to secure each owner’s pro rata share of various
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anticipated closure and remediation obligations. The amount of financial assurance
required may vary due to the uncertainty associated with remediation activities. Please
refer to the Colstrip section for additional information on the AOC/CCR related activities.

Particulate Matter (PM)
Particulate Matter (PM) is the term used for a mixture of solid particles and liquid droplets
found in the air. Some particles, such as dust, dirt, soot, or smoke, are large or dark
enough to see with the naked eye. Others are so small they are only detectable with an
electron microscope. Particle pollution includes:
 PM10: inhalable particles, with diameters that are generally 10 micrometers and
smaller; and
 PM2.5: fine inhalable particles, with diameters generally 2.5 micrometers and
smaller.

There are different standards for PM10 and PM2.5. Limiting the maximum amount of PM
to be present in outdoor air protects human health and the environment. The CAA
requires EPA to set National Ambient Air Quality Standards (NAAQS) for PM, as one of
the six criteria pollutants considered harmful to public health and the environment. The
law also requires periodic EPA reviews of the standards to ensure that they provide
adequate health and environmental protection and to update standards as necessary.

Avista owns and/or has operational control of the following generating facilities that
produce PM: Boulder Park, Colstrip, Coyote Springs 2, Kettle Falls, Lancaster, Northeast
and Rathdrum. Table 4.9 shows each of plants, their location, status of the surrounding
area with NAAQS for PM2.5 and PM10, operating permit, and PM pollution controls.

Appropriate agencies issue air quality operating permits. These operating permits require
annual compliance certifications and renewal every five years to incorporate any new
standards including any updated NAAQS status.

Threatened and Endangered Species and Wildlife
A number of species of fish in the Northwest are listed as threatened or endangered under
the Federal Endangered Species Act (ESA). Efforts to protect these and other species
have not significantly affected generation levels at our facilities. Avista is implementing
fish protection measures at our Clark Fork hydroelectric project under a comprehensive
settlement agreement. The restoration of native salmonid fish, including bull trout, is a
key part of the agreement. The result is a collaborative native salmonid restoration
program with the U.S. Fish and Wildlife Service, Native American tribes and the states of
Idaho and Montana, consistent with requirements of our FERC license.

Various statutory authorities, including the Migratory Bird Treaty Act, have established
penalties for the unauthorized take of migratory birds. Some of our facilities can pose
risks to a variety of such birds. We have and follow avian protection plans for these
facilities.

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Table 4.9: Avista Owned and Controlled PM Emissions

Thermal
Generating
PM2.5
NAAQS
PM10
NAAQS
Air Operating
Permit
PM Pollution Controls
Boulder Park Attainment Maintenance Minor Source Pipeline Natural Gas
Colstrip Attainment Non-Major Source Fluidized Bed Wet Scrubber
Coyote Springs Attainment Attainment Major Source Pipeline Natural Gas, Air
Kettle Falls Attainment Attainment Major Source Multi-clone collector,
Lancaster Attainment Attainment Major Source Pipeline Natural Gas, Air
Northeast Attainment Maintenance Minor Source Pipeline Natural Gas, Air
Rathdrum Attainment Attainment Major Source Pipeline Natural Gas, Air

Climate Change - Federal Regulatory Actions
In June 2019, the EPA released the final version of the Affordable Clean Energy (ACE)
rule, the replacement for the Clean Power Plan (CPP). The final ACE rule combined three
distinct EPA actions. First, EPA finalized the repeal of the CPP. The CPP was comprised
of three “building blocks” identified by the EPA as follows:

 Reducing CO2 emissions by undertaking efficiency projects at affected coal-fired
power plants (i.e., heat-rate improvements);
 Reducing CO2 emissions by shifting electricity generation from affected power
plants to lower-emitting power plants (e.g., natural gas plants); and
 Reducing CO2 emissions by shifting electricity generation from affected power
plants to new renewable energy generation.

Notably, the second and third building blocks, responsible for the majority of projected
emission reductions, were premised on “beyond the fence” measures to reduce
emissions. Second, the EPA finalized the ACE rule, which comprised the EPA’s
determination of the Best System of Emissions Reduction (BSER) for existing coal-fired
power plants and procedures that would govern States’ promulgation of standards of
performance for such plants within their borders. EPA set the final BSER as heat rate
efficiency improvements based on a range of “candidate technologies” that can be applied
to a plant's operating units and requires that each State determine which apply to each
coal-fired unit based on consideration of remaining useful plant life. Contrary to the CPP,
ACE relied solely on emission reductions from the specific source, or “inside the fence.”
Lastly, the ACE rule included implementing regulations for State plans.

In January 2021, the U.S. Court of Appeals for the District of Columbia Circuit (D.C.
Circuit) vacated the ACE Rule and remanded the record back to the EPA for further
consideration consistent with its opinion, finding that the EPA misinterpreted the CAA
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when it determined that the language of Section 111 barred consideration of emissions
reduction options that were not applied at the source. The Court also vacated the repeal
of the CPP. The EPA will now act on remand, and it is unclear what next steps the EPA
will take. Given the complex and uncertain legal record with respect to the CPP, and the
confirmation testimony of the incoming EPA Administrator that the Court’s ruling was an
opportunity for the EPA to “take a clean slate” in this area, we expect new rulemaking in
the future.

Climate Change - State Legislation and State Regulatory Activities
Washington and Oregon both adopted non-binding targets to reduce greenhouse gas
emissions with an expectation of reaching the targets through a combination of renewable
energy standards, eventual carbon pricing mechanisms (such as cap and trade regulation
or a carbon tax), and assorted “complementary policies.” Neither state has yet mandated
specific reductions, but instead have enacted other targets to reduce greenhouse gas
emissions. Washington State enacted Senate Bill 5116, the Clean Energy Transformation
Act (CETA). As stated elsewhere in this IRP, CETA aims to reduce greenhouse gas
emissions from specific sectors of the economy through direct regulation including
electricity generation. CETA requires utilities to eliminate coal-fired resources from
Washington retail rates by the end of 2025, achieve carbon neutrality by 2030 with no
more than 20 percent of load met by alternative compliance means, and serve all retail
load with renewable and non-emitting resources by 2045. Additional legislation with goals
to reduce greenhouse gas emissions through a variety of measures have been proposed
in both states. Any legislation that becomes law will be incorporated into future IRPs.

Washington and Oregon apply greenhouse gas emissions performance
standards (EPSs) to electric generation facilities used to serve retail loads in their
jurisdictions, whether the facilities are located within those respective states or
elsewhere. The EPS prevents utilities from constructing or purchasing generation
facilities or entering into power purchase agreements of five years or longer duration to
purchase energy produced by plants that, in any case, have emission levels higher than
1,100 CO2 equivalency (CO2e) pounds per MWh. The Washington State Department of
Commerce reviews this standard every five years. The last review was in September
2018 where it adopted a new rate of 925 pounds CO2e per MWh.

Energy Independence Act (EIA)
The EIA in Washington requires electric utilities with over 25,000 customers to acquire
qualified renewable energy resources and/or renewable energy credits equal to 15
percent of the utility's total retail load in Washington in 2020 and beyond. Utilities under
EIA regulation must also meet biennial energy conservation targets. Failure to comply
with renewable energy and efficiency standards result in penalties of as much as $50 per
MWh of deficiency. Avista meets the requirements of the EIA through a combination of
hydro upgrades, wind, biomass, and renewable energy credits. Beginning in 2030, if a
utility is compliant with CETA, the utility is deemed to meet the requirements of the EIA.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Colstrip
Colstrip was built as a four-unit coal plant in Eastern Montana. Avista is 15 percent owner
in Units 3 and 4. A complete list of the ownership shares and sizes of the plant is in Table
4.10. Units 1 and 2 retired in early 2020. Washington’s CETA prohibits utilities from
charging and using coal resources for Washington retail customers after 2025.

Figure 4.5: Colstrip Plant

Table 4.10: Colstrip Ownership Shares

Unit 3 Units 4
Operating Capacity (MW) 740 740
Year On-Line 1984 1986

Owners
Avista 15% 15%
Northwestern Energy 0% 30%
PacifiCorp 10% 10%
Portland General Electric 20% 20%
Talen Energy, LLC 30% 0%
Puget Sound Energy 25% 25%

Coal Supply
Colstrip is supplied from an adjacent coal mine under coal supply and transportation
agreements. Avista, along with the other owners agreed to an extension of this agreement
through 2025 with extension options. The specific terms of the agreement are
confidential.

Water and Waste Management
Colstrip uses water from the Yellowstone River for steam production, air pollution
scrubbers and cooling purposes. The water travels through a 29-mile pipeline to Castle
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Rock Lake, a surge pond and water supply source for the plant and the Town of Colstrip.
From Castle Rock Lake, water moves to holding tanks as needed throughout the plant
site. The water recycles until it is ultimately lost through evaporation, also known as zero-
discharge. An example of this reuse is how the plant removes excess water from the
scrubber system fly ash, creating a paste product similar to cement. The paste flows to a
holding pond while clear water is reused. Similarly, the bottom ash flows to a holding
pond, where it is dewatered and the water is reused.

The plant uses three major areas for water and waste management. The first are at-plant
facilities, in which all four units, including the now-retired Units 1 and 2, shared use of the
ponds. The second major area, supporting Units 3 and 4 operations, is the Effluent
Holding Pond (EHP). This area is 2.5 miles to the south east of the plant site. Avista is
responsible for its proportional share of the EHP Area. The third storage area is the Stage
One Effluent Pond (SOEP)/Stage Two Effluent Pond (STEP); these ponds dispose fly
ash from the scrubber slurry/paste from Units 1 and 2. These ponds are nearly two miles
to the northwest of the plant. Avista does not have ownership or responsibility in this area.
Avista is therefore responsible for its share of the plant site area and EHP facilities. Figure
4.6 shows a map of the different storage areas at Colstrip.

Colstrip will covert to dry ash storage in 2022. The master plan for site wide ash
management is filed with the MDEQ-AOC13 and additional information on CCRs is
available at Talen’s website14. This plan includes removing Boron, Chloride and Sulfate
from groundwater, closure of the existing ash storage ponds, and installation of a new
water treatment system along with a dry ash storage facility. Each of the new facilities are
required, regardless of the length of the plant’s continuing operations. Avista has posted
bonds for nearly $6 million in 2018 for cost assurance and an additional $7 million in 2019
related to Units 3 and 4 closure. These amounts are updated annually, increasing as
clean-up plans are finalized and approved in the coming years and then decreasing over
time as remediation activities are completed.

Post 2025 Considerations
Three primary drivers affect operational and financial risks defining the future viability of
the Company’s share of Colstrip Units 3 and 4. These include the ownership and
operating agreement, the coal contract and Washington CETA law.

The ability to shut down Colstrip Units 3 and 4 is governed by the ownership and operation
agreement. No decisions have been made by the ownership group regarding whether
Colstrip Unit 3 and/or Unit 4 will continue to operate to the December 31, 2025 date
imposed by CETA or if the units will continue to operate beyond 2025.

Avista obtains its share of the coal for Colstrip Units 3 and 4 pursuant to a coal supply
agreement with Westmoreland Rosebud Mining, LLC. The coal supply agreement expires
on December 31, 2025 but could be extended up to December 31, 2029. If the coal supply

13 http://deq.mt.gov/DEQAdmin/mfs/ColstripSteamElectricStation.
14 https://www.talenenergy.com/ccr-colstrip/.
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agreement is extended beyond December 31, 2025, the parties will need to negotiate a
new price for coal for the extended term.

Figure 4.6: Map of Colstrip Water Storage

Section 3 of CETA states: “On or before December 31, 2025, each electric utility must
eliminate coal-fired resources from its allocation of electricity.”15 That is, after December
31, 2025, the costs and benefits associated with coal-fired resources (except for
decommissioning and remediation costs), including costs and benefits associated with
Avista’s share of Colstrip Units 3 and 4, cannot be included in Avista’s Washington retail
electricity rates.16 Coal-fired resources must be fully depreciated under the law by
December 31, 2025.17

It is difficult to speculate on all potential Colstrip scenarios; however, in general, there are
three likely outcomes:
 one or more of the units will continue to operate with the same ownership;
 one or more of the units will continue to operate, but the ownership in the
units will change; or
 both units will be shut down.

15 “Allocation of electricity” means, for the purposes of setting electricity rates, the costs and benefits
associated with the resources used to provide electricity to an electric utility’s retail electricity customers
that are located in this state.
16 See Clean Energy Transformation Act at Section 2 (defining “electric utility”); Clean Energy
Transformation Act at Section 3.
17 Clean Energy Transformation Act at Section 3.
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If units continue to operate after December 31, 2025, and Avista remains an owner, a
number of items will need to be addressed. First, Avista will need to evaluate its
contractual obligations under the existing ownership and operation agreement. Second,
because Avista is contractually required to supply its share of coal to operate the unit(s),
Avista will need to either join in extending the existing coal supply agreement or make
other arrangements. Finally, Avista will need to determine how it is going to comply with
the requirements of any applicable laws, including the Washington CETA.

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5. Energy Efficiency
Avista’s energy efficiency programs provide cost-effective opportunities for customers to
save energy by replacing old equipment with better performing, energy efficient
equipment. The energy efficiency programs offer a wide array of low-cost measures to
our customers. Current programs with the highest impacts on energy savings include non-residential lighting, residential home measures and direct install programs. Avista’s energy efficiency programs regularly meet or exceed regional shares of the efficiency
targets outlined by the Northwest Power and Conservation Council (NPCC).

Figure 5.1 illustrates Avista’s historical electricity conservation acquisitions. Avista has
acquired 252 aMW of energy efficiency since 1978; however, the 18-year average measure life of the conservation portfolio means some measures are no longer reducing
load as the measure has either became code or standard practice. The 18-year measure
life accounts for the difference between the cumulative and online trajectories in Figure
5.1. Currently 160 aMW of energy efficiency serves customers, representing nearly 14.5 percent of 2019 load.
Avista’s energy efficiency programs provide energy efficiency and education offerings to
the residential, low income, commercial and industrial customer segments. Program delivery mechanisms include prescriptive, site-specific, regional, upstream, behavioral,
market transformation and third-party direct install options. Prescriptive programs provide
fixed cash incentives based on an average savings assumption for the measure across
the region. Prescriptive programs work best where uniform measures or offerings apply
to large groups of similar customers. Examples of prescriptive programs include the installation of qualifying high-efficiency heating equipment or replacement of T8 florescent
strip lighting with a high-efficiency LED lamp.

Site-specific programs, or customized offerings, provide cash incentives for cost-effective energy saving measures or equipment that are analyzed and contracted but do not meet
prescriptive rebate requirements. Site-specific programs require customized approaches
for commercial and industrial customers because of the unique characteristics of each
premise and/or process. Other delivery methods build off these offerings with up- and
mid-stream retail buy-downs of low-cost measures, free-to-customer direct install programs or coordination with regional market transformation efforts. In addition to
developing and delivering incentive offerings, Avista also provides technical assistance
to help educate and inform customers about various types of efficiency measures.

Section Highlights
• Avista’s energy efficiency programs reduce loads by nearly 14.5 percent, or 160
aMW.
• This IRP evaluated over 7,300 measure options covering all major end use
equipment, as well as devices and actions to reduce energy consumption for
this IRP.
• The 2022-23 Washington EIA penalty threshold is 88,889 MWh.
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Figure 5.1: Historical Conservation Acquisition (system)
The Conservation Potential Assessment
Avista retained Applied Energy Group (AEG) as an independent consultant to assist in
developing a Conservation Potential Assessment (CPA) for this IRP. The CPA is the basis
for the energy efficiency portion of this plan. The CPA identifies the 24-year potential for
energy efficiency and provides data on resources specific to Avista’s service territory for
use in the resource selection process and in accordance with the Energy Independence Act’s (EIA) energy efficiency goals. The potential assessment considers the impacts of
existing programs, the influence of known building codes and standards, technology
developments and innovations, changes to the economic influences and energy prices.
The CPA report is included in Appendix E of this IRP and the list of energy efficiency
measures are in Appendix I.
AEG first developed estimates of technical potential, reflecting the adoption of all
conservation measures, regardless of cost-effectiveness or customers’ likeliness to
participate. The next step identified the achievable technical potential; this measure
modifies the technical potential by accounting for customer adoption constraints by using the Power Council’s 2021 Plan ramp rates. The estimated achievable technical potential,
along with associated costs, feed into the PRiSM model to select cost-effective measures.
AEG took the following steps shown in Figure 5.2 to assess and analyze energy efficiency
and potential within Avista’s service territory.
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Figure 5.2: Analysis Approach Overview
In short, the potential assessment performed by AEG included the following steps:
1. Perform a market characterization to describe sector-level electricity use for the
residential, commercial and industrial sectors for the 2019 base year.
2. Develop a baseline projection of energy consumption and peak demand by sector,
segment and end use for 2019 through 2045.
3. Define and characterize several hundred conservation measures to be applied to all
sectors, segments and end uses.
4. Estimate Technical Potential and Achievable Technical Potential at the measure level in terms of energy and peak demand impacts from conservation measures for 2019-
2045.
Market Segmentation
The CPA considers Avista customers by state and by sector. The residential sector
includes single-family, multi-family, manufactured home and low-income customers1 and
is based on Avista’s customer data and U.S. Census data from the American Community
Survey (ACS). For the residential sector, AEG utilized Avista’s customer data and prior
CPA ratios developed from census information. AEG incorporated information from the
Northwest Energy Efficiency Alliance’s (NEEA) Commercial Building Stock Assessment
to assess the commercial sector by building type, installed equipment and energy consumption. Avista analyzed the industrial sector as a whole for each state because of
their unique energy needs. AEG characterized energy use by end use within each
1 The low-income threshold for this study is 200 percent of the federal poverty level. Low-income information
is available from U.S. census data and the American Community Survey data.
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segment in each sector, including space heating, cooling, lighting, water heat or motors;
and by technology, including heat pump and resistance-electric space heating.
The baseline projection is a “business as usual” metric without future utility conservation
or energy efficiency programs. It estimates annual electricity consumption and peak
demand by customer segment and end use absent future efficiency programs. The baseline projection includes the impacts of known building codes and energy efficiency
standards as of 2018 when the study began. Codes and standards have direct bearing
on the amount of energy efficiency potential due to the reduction in remaining end uses with potential for efficiency savings. The baseline projection accounts for market changes
including:

• customer and market growth;
• income growth;
• retail rates forecasts;
• trends in end use and technology saturation levels;
• equipment purchase decisions;
• consumer price elasticity;
• income; and
• persons per household.

For each customer class, AEG compiled a list of electrical energy efficiency measures and equipment, drawing from the NPCC’s 2021 Power Plan, the Regional Technical
Forum and other measures applicable to Avista. The 7,300 individual measures included
in the CPA represent a wide variety of end use applications, as well as devices and actions able to reduce customer energy consumption. The AEG study includes measure
costs, energy and capacity savings and estimated useful life.
Avista, through its PRiSM model, considers other performance factors for the list of
measures and performs an economic screening on each measure for every year of the
study to develop the economic potential of Avista’s service territory and individually by
state.

Avista supplements energy efficiency activities by including potentials for distribution
efficiency measures consistent with EIA conservation targets and the NPCC 2021 Power
Plan.
Overview of Energy Efficiency Potential
AEG’s approach adhered to the conventions outlined in the National Action Plan for Energy Efficiency Guide for Conducting Potential Studies.2 The guide represents
comprehensive national industry standard practice for specifying energy efficiency
potential. Specifically, two types of potential were included in this study, as discussed below. Table 5.1 shows the CPA results for Technical and Achievable Technical Potential
by state.
2 National Action Plan for Energy Efficiency (2007). National Action Plan for Energy Efficiency Vision for
2025: Developing a Framework for Change. www.epa.gov/eeactionplan.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Table 5.1: Cumulative Potential Savings (Across All Sectors for Selected Years)
2022 2023 2024 2031 2041
Technical Potential Technical Potential is defined as the theoretical upper limit of conservation potential.
It assumes customers adopt all feasible measures regardless of cost. At the time of
existing equipment failure, customers replace their equipment with the most efficient
option available.
In new construction, customers and developers also choose the most efficient
equipment option relative to applicable codes and standards. Non-equipment measures, which may be realistically installed apart from equipment replacements, are implemented according to ramp rates developed by the NPCC for its 2021 Power
Plan, applied to 100 percent of the applicable market. The Technical Potential case is
a theoretical construct and is provided primarily for planning and informational purposes.

Achievable Technical Potential
Achievable Technical Potential refines Technical Potential by applying customer participation rates that account for market barriers, customer awareness and attitudes,
program maturity and other factors affecting market penetration of energy efficiency
measures. AEG used ramp rates from the Council’s 2021 Power Plan in development
of the Achievable Technical Potential.
For the Achievable Technical Potential case, a maximum achievability multiplier of 85
to 100 percent is applied to the ramp rate, per Council methodology. This achievability
factor represents an achievable potential, which can reasonably be acquired through available mechanisms, regardless of how conservation is achieved. Thus, the market
applicability assumptions utilized in this study include savings outside of utility
programs. PRiSM Co-Optimization
Avista’s identifies achievable economic conservation potential by concurrently evaluating
supply- and demand-side resources together in Avista’s PRiSM model. In PRiSM, the energy efficiency resources compete with supply- and demand resource options to meet
Avista resource deficits. Energy efficiency measures benefit from additional value
streams, such as 10 percent more energy and capacity from the Power Act Preference in Washington, as compared to other resources. Energy efficiency also receives additional
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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financial benefits by including financial savings from reducing line losses and avoided
transmission and distribution costs. For Washington, an additional credit is included
based on regional greenhouse gas emissions reductions priced at the social cost of carbon and financial benefits for non-energy impacts.
Energy Efficiency Targets
Cost effective energy efficiency will lower system sales by 113 aMW by 2041; this
translates into a 9.6 percent savings. Of the total energy efficiency savings estimates,
Idaho saves 23 percent of the saving potential compared to Washington’s 77 percent.
Washington receives a larger percentage of the savings because of the higher avoided
costs. These higher avoided costs include greenhouse gas emissions benefits priced at the social cost of carbon, non-energy impacts, and the 10 percent Power Act preference
adder. Figure 5.3 shows the total savings by state for selected years. Commercial and
Residential customers contribute to most of the savings of the three major customer
classes. Savings for each class are shown by state in Figure 5.4 Figure 5.3: Conservation Potential Assessment - 20-Year Cumulative GWh

32
69
508
772
12 26
143
213
Washington
Idaho
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Figure 5.4: Energy Efficiency Savings by Segment
Washington Biennial Conservation Plan
The IRP process provides the energy efficiency targets for Washington’s EIA Biennial
Conservation Plan. Pursuant to requirements in Washington, the biennial conservation
target must be no lower than a pro rata share of the utility’s ten-year conservation
potential. In setting the Company’s target, both the two-year achievable potential and the ten-year pro rata savings are determined with the higher value used to inform the EIA
Biennial target. Figure 5.5 shows the annual selection of new energy efficiency compared
to the 10-year pro-rata share methodology.

For the 2022-2023 CPA, the two-year achievable potential is 69,174 MWh for Washington electric operations. The pro-rata share of the utility’s ten-year conservation potential is
102,566 MWh which is used in the calculation of the biennial target. Table 5.2 contains
achievable conservation potential for 2022-2023 using the PRiSM methodology. Also
included is the energy savings expected from the 2022 and 2023 feeder upgrade projects
shown below in Table 5.3.
WA ID WA ID WA ID
2023 2031 2041
Industrial 12.0 8.4 62.5 42.8 86.4 59.1
Commercial 39.3 10.0 255.3 57.4 359.2 95.3
Residential 17.9 7.2 190.0 42.6 326.8 58.8
Total 69.2 25.6 507.8 142.9 772.4 213.2
0
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h
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Figure 5.5: Washington Annual Achievable Potential Energy Efficiency (Gigawatt Hours)
Table 5.2: Biennial Conservation Target for Washington Energy Efficiency

2022-2023 Biennial Conservation Target (MWh)
EIA Target 101,785
Total Utility Conservation Goal 106,904
Utility Specific Conservation Goal 94,008
EIA Penalty Threshold 88,889
Table 5.3: Annual Achievable Potential Energy Efficiency (Megawatt Hours)

2022 Feeder Upgrades 218.8 0 218.8
2023 Feeder Upgrades 0 245.6 245.6

3 NEEA yet to be determined for the 2022-2023 Biennium
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Energy Efficiency Related Financial Impacts
The Washington EIA requires utilities with over 25,000 customers to acquire all cost-
effective and achievable energy conservation.4 For the first 24-month period under the
law, 2010-2011, this equaled a ramped-in share of the regional 10-year conservation
target identified in the Seventh Power Plan. Penalties of at least $50 per MWh exist for
utilities not achieving EIA targets.
The EIA requirement to acquire all cost-effective and achievable conservation may pose
significant financial implications for Washington customers. Based on CPA results, the projected 2021 conservation acquisition cost to Washington electric customers is
approximately $17.9 million. This amount grows to $35.8 million by 2022 totaling to $197
million over this 10-year period. Costs are projected to continue increasing after 2031 to over $376 million in 2041. In total, the levelized price for Washington’s savings is 3.5
cents per kWh.

For Idaho, Avista continues to pursue all cost-effective and achievable energy efficiency.
Based on CPA results, the projected 2021 Idaho conservation acquisition cost to electric customers is approximately $7.6 million. This amount is projected to grow to $15 million
by 2022 totaling to $83 million over this 10-year period. Costs are projected to continue
to increase after 2031 to more than $159 million in cumulative costs by 2041. In total, the levelized price for Idaho’s energy efficiency is 3.4 cents per kWh.

Figure 5.6 shows the annual cost in millions of nominal dollars for the utility to acquire the projected electric achievable potential and administer the programs for each state.
Figure 5.6: Cumulative Energy Efficiency Costs

4 The EIA defines cost effective as 10 percent higher cost than a utility would otherwise spend on energy
acquisition.
Mi
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l
i
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n
s
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Integrating Results into Business Planning and Operations
The CPA and IRP energy efficiency evaluation processes provide high-level estimates of
conservation cost-effectiveness and acquisition opportunities. Results establish baseline
goals for continued development and enhancement of energy efficiency programs, but do not provide enough detail to form an actionable acquisition plan. Avista uses results from
both processes to establish a budget for energy efficiency measures, determine the size
and skillsets necessary for future operations and identify general target markets for
energy efficiency programs. This section discusses recent operations of the individual sectors and energy efficiency business planning.

The CPA is used for implementing energy efficiency programs in the following ways:
• Identifying conservation resource potentials by sector, segment, end use and
measure of where energy savings may come from. Energy efficiency staff uses CPA results to determine the segments and end uses/measures to target.
• Identifying measures with the highest benefit-cost ratios to help the utility acquire
the highest benefits for the lowest cost. Ratios evaluated include total resource cost (TRC) in Washington and utility cost test (UCT) in Idaho.
• Identifying and targeting measures with large potential but significant adoption barriers that the utility may be well-positioned to address through innovative
program design or market transform efforts.
• Optimizing the efficiency program portfolio by analyzing cost effectiveness, potential of current measures and programs, determining potential new programs,
ideal program changes and necessary program sunsets.
The CPA illustrates potential markets and provides a list of cost-effective measures to
analyze through the ongoing energy efficiency business planning process. This review of
both residential and non-residential program concepts and sensitivity to more detailed
assumptions feed into program planning.
Residential Sector Overview
The Company’s residential portfolio of efficiency programs uses several approaches to engage and encourage customers to consider energy efficiency improvements for their
home. Prescriptive rebate programs are the main component of this portfolio, augmented
with other interventions. Other interventions include select distribution of low-cost lighting and weatherization materials, direct-install programs as well as multi-faceted,
multichannel outreach and customer engagement.

Residential customers received over $7.7 million in rebates in 2019 to offset the cost of implementing these energy efficiency measures. All programs within the residential
portfolio contributed over 28,295 MWh to the 2019 annual energy savings.
Low-Income Sector Overview
The Company leverages the infrastructure of several network Community Action
Agencies (CAA) and one tribal weatherization organization to deliver energy efficiency
programs for the Company’s low-income residential customers in Avista’s service
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 105 of 317
territory. CAAs have resources to income qualify, prioritize and treat clients’ homes based upon several characteristics that are not available to Avista. Beyond Avista’s annual
funding, the agencies have other monetary resources to leverage for home
weatherization and other energy efficiency measures. The agencies have both in‐house
and/or contract crews available to install many of the efficiency program measures.
Avista’s general outreach for this sector is a “high touch” customer experience for
vulnerable customer groups including seniors and those with limited incomes. Each
outreach encounter includes information about bill payment options and energy management tips, along with the distribution of low-cost weatherization materials. Many events are coordinated each year, including Avista-sponsored energy fairs, and the
energy resource van. Avista also partners with community organizations to reach these
customers through other means such as area food bank/pantry distribution sites, senior activity centers, or affordable housing developments. Low-income energy efficiency programs contributed 898 MWh of electricity savings in 2019.

Non-Residential Sector Overview Non-residential energy efficiency programs deliver energy efficiency through a
combination of prescriptive and site-specific offerings. Any measure not offered through
a prescriptive program is eligible for analysis through the site-specific program, subject to
the criteria for program participation. Prescriptive paths for the non-residential market are preferred for small and uniform measures, but larger measures may also fit where
customers, equipment and estimated savings are reasonably non-homogenous.

In 2019, more than 1,687 prescriptive and site-specific nonresidential projects received funding. Avista contributed over $8 million for energy efficiency upgrades to offset costs
in nonresidential applications. Non-residential programs realized over 43,799 MWh in
annual first‐year energy savings in 2019.
Other Energy Efficiency Analysis
Conservation’s Transmission & Distribution Deferral Analysis
Cost-effective energy efficiency programs require a review of cost versus potential
benefits. One benefit is the avoidance or deferral of generation and distribution system
investments. Avoided generation investments are straightforward but avoided transmission and distribution (T&D) system components tend to be less straightforward
as the investments are lumpy, location specific and may or may not include energy
efficiency due to the thermal limitations of the system.
The 2017 IRP Washington acknowledgement letter requested Avista determine whether
to move the T&D benefits estimates to a forward-looking value versus a historical value.
With many changes occurring in energy efficiency in the future, there is merit in exploring
the deferral value on the future use of T&D systems. A forward-looking T&D deferral value could provide better alignment between the expected use of the Company’s T&D system
and the valuation of customer benefits. Conversely, estimates on future T&D values can
be more difficult to quantify and are subject to many iterations throughout the T&D
planning process.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 106 of 317
The NPCC’s methodology divides the estimated capital investment over a 5 to 10-year period by the estimated capacity gained by that investment. Note that this value is refined
by applying a capital growth investment ratio, a power factor, a regionally set discount
rate and the assumption that the average measure has a life of 35 years. The result of these calculations is deferred values of $13.01 per kW-year and $12.37 per kW-year for
transmission and distribution respectively and a combined value of $25.38 per kW-year.
Table 5.4 illustrates the values calculated for the Company’s T&D deferred benefits for
energy efficiency.
Table 5.4: Transmission and Distribution Benefits (System) Transmission Distribution
Capital Investment (est.) $57,400,000 $ 651,706,715 Capacity Gained (est. MW) 275 512
Capital Growth Investment Ratio 100% 26%
Power Factor 0.98 0.98
Discount rate 5% 5%
Asset lifetime (Years) 35 35
T&D Carrying Charge 6.1% 6.1% Results Separate ($/kW-year) 13.01 12.37
Result Combined ($/kW-year) 25.38

The impact of implementing a forward-looking T&D deferral value attempts to better align with known future activity; however, data on future T&D investments as they relate to
energy efficiency is less reliable as it is not a primary consideration for many T&D projects.
While the overall impact of the T&D deferral methodology used is minimal, Avista remains
open to exploring alternative methodologies as they become available.
Non-Energy Impacts
Avista will partner with a third-party consultant to identify non-energy impact (NEI)
benefits or costs within its service territory that have historically not been quantified. In order to provide the IRP with an estimate for the benefits, Avista is using an interim value
of $8.90 per MWh as a proxy for the yet to be identified impacts until more robust
estimates can be determined later in 2021. The interim NEI values are based on a 2019
EPA report entitled “Public Health Benefits per kWh of Energy Efficiency and Renewable Energy in the United States: A Technical Report”. This report identifies NEI values for
regions throughout the U.S. including the Pacific Northwest. NEI values identified are not
tied to specific measures, but rather are applicable to all generated energy, which allows the values to be easily applied. However, the report has inherent limitations when
applying the values to a specific utility, as the study does not identify each county in the
Pacific Northwest but takes an aggregated approach by selecting counties across
Washington, Oregon, Idaho, Montana, Wyoming and Nevada. This aggregation limits the ability to derive unique NEI values for Avista and its own fuel mix.

To address this limitation, Avista’s energy efficiency team used the AVERT calculator, a
tool used in the report to identify each region’s NEI values, to determine emissions rates for each state within the Pacific Northwest region. The results of that analysis show
Washington accounted for only 20 percent of the generation and about half of the
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 107 of 317
emissions rate compared to the aggregated Pacific Northwest data. Avista imported the AVERT data into the COBRA Model, also utilized by the EPA study to replicate the health
benefits from the region. The resulting NEI value range was between $5.46 and $12.34
per MWh which is about half of the range for the Pacific Northwest region. While this NEI value range is closer to Avista’s emissions rate and fuel mix, the actual NEI value for
Avista’s service territory is unknown because Washington data included only Clark,
Cowlitz, Grays Harbor, Klickitat, Lewis, Pierce, Skagit, and Whatcom counties. King and
Spokane counties were excluded in the report. Based on a comparison of Avista’s wood smoke study conducted in 2018, Avista had a NEI cost of $4.00 to $9.00 per MWh. Using
the $5.46 to $12.34 per MWh range is close to this amount and is a reasonable
approximation. The midpoint of this range is $8.90 per MWh, which was applied uniformly
to account for non-energy impacts within the 2021 IRP. The NEI values estimates used do not take the expectation of Avista’s increasingly cleaner generation mix into
consideration. This is an area for further consideration in the more detailed Avista NEI
study described above. Social Cost of Carbon
For Washington programs, energy efficiency benefits economically from an adjustment
to include the benefit from regional greenhouse gas emission reductions. Avista estimated the incremental amount of greenhouse emissions reductions per MWh of
energy efficiency for the northwest and applied this savings to each MWh of potential
program savings valued at the social cost of carbon. Details regarding the market impacts
of energy efficiency are included in Chapter 10 and the net economic benefit from including the social cost of carbon for energy efficiency is in the avoided cost shown in
Figure 5.7.
Combined Heat and Power Avista has not identified any combined heat and power opportunities within its service
territory for this plan. Currently, Avista has one combined heat and power customer in
Idaho selling power to Avista under a PURPA contract and one customer in Washington
that is exploring the feasibility of a project. Due to the uncertainty of a future project, no additional analysis is required at this time.
Energy Efficiency Avoided Costs
The energy efficiency avoided cost is useful for the energy efficiency evaluation and
acquisition team to conduct financial analysis of potential programs in between IRP analyses. The process to estimate avoided cost calculates the marginal cost of energy
and capacity of the resources selected in the PRS. The calculation process is similar to
the generation resources discussed in Chapter 11 but differs in the case of energy
efficiency for the capacity and clean energy calculation by removing energy efficiency as a resource option to determine its avoided capacity and energy costs.

The energy efficiency avoided costs include additional premium components depending
on whether the program is being evaluated for Washington or Idaho. The Washington analysis (Figure 5.7) includes additional societal costs such as non-energy impacts, social
cost of carbon and the Power Act’s 10 percent premium adder. Washington programs
also reduce the need for premium priced clean energy resources and this benefit is also
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 108 of 317
factored into the analysis. The total energy avoided cost is $105.83 per MWh and $151.25
per kW-year for capacity. For Idaho (Figure 5.8) the costs considered include the avoided
energy, capacity, T&D losses and avoided T&D capital. The total of these avoided costs for Idaho is $29.63 per MWh and $137.50 per kW-year for capacity5.
Figure 5.7: Washington Energy Efficiency Avoided Cost

Figure 5.8: Idaho Energy Efficiency Avoided Cost

5 Avista previously included the Northwest Power Act 10 percent premium for Idaho energy efficiency avoided costs. Avista chose not to include this adjustment to align all assumptions of this plan to only
include measurable utility cost avoided by the utility.
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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Chapter 6: Demand Response

Avista Corp 2021 Electric IRP 6-1
6. Demand Response

Historically, demand response (DR) programs provide capacity at times when wholesale
prices are unusually high, when a shortfall of generation or transmission occurs, or during
an emergency grid-operation situation. Traditional DR, time-of-use rates, peak time
rebates, direct load control programs or bi-lateral agreements are programs to incent load
reductions to specific enrolled customers during such periods until the load event is over
or the customer has met the contracted commitment. More recently, DR driven initiatives
are providing reliable ancillary service support in wholesale markets with future
expectations of providing additional services to the modern grid, becoming especially
important in supporting clean energy goals.

Avista’s experience with DR dates back at least to the 2001 Western Energy Crisis. Avista
responded with all-customer and irrigation customer buy-back programs and bi-lateral
agreements with its largest industrial customers. These programs, along with enhanced
commercial and residential energy efficiency programs, reduced the need for purchases
in very high-cost wholesale electricity markets. A July 2006 multi-day heat wave prompted
Avista to request DR voluntarily through media outlets by asking customers to conserve
energy due to the extreme regional and local temperatures not seen to that point in the
Spokane Area since 1961. Avista also initiated short-term agreements with large
industrial customers to curtail loads. Avista estimated those DR projects reduced loads
by 50 MW during the 2006 event. After the 2006 event, Avista implemented additional
short-term bi-lateral DR agreements with its largest customers for use during grid
emergencies.

2007-2009 Residential Demand Response Pilot
The 2006 heat wave event led to Avista conducting a two-year residential load control
pilot between 2007 and 2009 to study specific DR technologies and examine cost-
effectiveness and customer acceptance. The DR pilot tested scalable Direct Load Control
(DLC) devices based on installations in approximately 100 volunteer households in
Sandpoint and Moscow, Idaho. The sample allowed Avista to test DR with the benefits of
a larger-scale project, but in a controlled, measurable and customer-friendly manner.
Avista installed DLC devices on residential heat pumps, water heaters, electric forced-air
furnaces and air conditioners to control operation during 10 scheduled events at peak
times ranging from two-to-four hours each. A separate group, within the same
communities, participated in an in-home-display device study as part of the pilot. The
program provided Avista and its customers experience with “near-real time” energy-usage
Section Highlights
 Avista’s demand response experience began in 2001.
 Avista contracted AEG to perform a residential and commercial demand
response potential assessment for this IRP.
 This IRP studied 16 demand response programs.
 An 8-hour demand response event receives a 60 percent peak credit against
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Chapter 6: Demand Response

Avista Corp 2021 Electric IRP 6-2
feedback equipment. Information gained from the pilot is summarized in a report filed with
the Idaho Public Utilities Commission1.

2009-2014 Smart Grid Demonstration Project
Following the North Idaho DR pilot program, Avista engaged in a DR program as part of
the Northwest Regional Smart Grid Demonstration Project (SGDP) with Washington State
University (WSU) and approximately 70 residential customers in Pullman and Albion,
Washington participated. Residential customer assets including forced-air electric
furnaces, heat pumps and central air-conditioning units received a Smart Communicating
Thermostat provided and installed by Avista. The DLC approach was non-traditional,
meaning the DR events were not prescheduled, but rather Avista controlled customer
loads through an automated process based on utility or regional grid needs while using
predefined customer preferences (no more than a two degree offset for residential
customers and an energy management system at WSU with a console operator). More
importantly, the technology used in the DR portion of the SGDP predicted if equipment
was available for participation in the control event, which provided real time feedback of
the actual load reduction due to the DR event. Additionally, WSU facility operators had
instantaneous feedback due to the integration between Avista and their building
management system. Residential customer notifications of the DR event occurred via
their smart thermostat. The SGDP began in 2009 and concluded in 2014. Avista reported
information gained from this project to the prime sponsor for use in the SGDP’s final
project report and compilation with other SGDP initiatives2.

Experiences from both DLC pilots showed participating customer engagement is high;
however, recruiting participants was challenging. Avista’s service territory has a high level
of natural gas penetration meaning many customers cannot participate in typical DLC
electric space and water heat programs. Additionally, customers did not seem overly
interested in the DLC programs as offered. BPA found similar challenges in gaining
customer interest in their regional DLC programs3. A 2019 Avista quantitative survey,
conducted by the Shelton Group, also found customer interest to participate in DR
programs to be low.

Avista paid customers direct incentives for program participation in both DLC pilots.
Incentive levels were a premium to recruit and retain customers and were not intended to
be scalable. Avista will need to conduct additional analysis to determine cost effective
payment strategies beyond pilots to mass-market DLC programs. Where Avista is not
able to harness adequate customer interest at cost-effective incentive levels, the future
of DR could be more limited than assumed in this IRP.

Avista will evaluate and consider DR programs to meet future load requirements where
cost effective compared to other alternatives and does not adversely influence reliability
or customer satisfaction with service. To fulfill this commitment, Avista sponsored several
DR potential assessment studies to identify the 20-year DR potential specific to Avista’s

1 https://puc.idaho.gov/fileroom/cases/elec/AVU/AVUE0704/company/20100303FINAL%20REPORT.pdf
2 https://www.smartgrid.gov/files/OE0000190_Battelle_FinalRep_2015_06.pdf.
3 BPA’s partnership with Kootenai Electric Coop, https://www.bpa.gov/EE/Technology/demand-
response/Documents/20111211_Final_Evaluation_Report_for_KEC_Peak_Project.pdf.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Chapter 6: Demand Response

Avista Corp 2021 Electric IRP 6-3
service territory for use in its resource selection process. The first DR study occurred for
the 2015 IRP in response to a 2013 IRP Action Item, and subsequent DR studies were
performed for the 2017, 2020 and this IRP.

Demand Response Potential Assessment Study
Avista retained AEG to study the potential of DR for all of Avista’s service territory for the
2022–2045 planning horizon. The study primarily sought to develop reliable estimates of
the magnitude, timing and costs of DR resources likely available to Avista for meeting
both winter and summer peak loads. The study’s focus was on resources assumed
achievable during the planning horizon, recognizing market dynamics may hinder DR
acquisition.

Figure 6.1 outlines AEG’s approach to determine potential DR programs in Avista’s
service territory. Many DR programs require Advanced Metering Infrastructure (AMI) for
settlement purposes. All DR pricing programs, behavioral and third-party contract DR
programs included in this study require AMI as an enabling technology. AMI deployment
is nearly complete in Washington at the time of this writing. AEG broadly assumed that
Avista would follow with AMI metering in Idaho beginning in 2022 and assumed a two-
year ramp rate for full deployment, finishing in 2024.

As with the CPA study for energy efficiency, AEG looked at Avista’s customer accounts
and rates schedules to characterize the market. This became the basis for customer
segmentation to determine the number of eligible customers in each market segment for
potential DR program participation.

The study compared Avista’s market segments to national DR programs to identify
relevant DR programs for analysis.

Figure 6.1: Program Characterization Process

This process identified several DR program options shown in Table 6.1. The different
types of DR programs include two broad classifications: curtailable/controllable DR and
rate design programs. Except for the behavioral program, curtailable/controllable DR
programs represent firm, dispatchable and reliable resources to meet peak-period loads.
This category includes Direct Load Control (DLC), Firm Curtailment (FC), thermal and
battery storage and ancillary services. Avista added large industrial curtailment that was
AMI
Infrastructure Analysis
• AMI is required for participation in certain programs
• Determines eligible populations for rate based options
• Analysis assumes all large C&I customers in the state have Interval Demand Recorder (IDR) meters
Select
Appropriate Programs
• Develop a list of appropriate programs
• Rates, direct load control, interruptible, economic, and storage options
Program Characterization
• Develop participation rates, impacts, cost, and other key program parameters
• In the context of high and low potential cases
Develop
Program Hierarchy
• Ensure the potential is not double counted between programs
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Chapter 6: Demand Response

Avista Corp 2021 Electric IRP 6-4
not part of the AEG study. Rate design options offer non-firm load reductions that might
not be available when needed, but rather create a reliable pattern of potential load
reduction. Pricing options include time-of-use and variable peak pricing. Each option
requires a new rate tariff for each state in Avista’s service territory.

Table 6.1: Demand Response Program Options by Market Segment

DR Program Participating Market Segment Season Impacted
Program
Type Option Com. Com./
Ind.
Large
Com./
Curtailable/
Controllable
DR
DLC Central AC X X X
DLC Smart X X X
DLC Smart X X X
DLC CTA-2045 X X X X
DLC Water Heating X X X X
DLC Vehicle X X X
DLC Smart X X X X
Third Party Contracts X X X X
Thermal Energy X X X X
Battery Energy X X X X X X
Behavioral X X X
Ancillary Services X X X X X X
Large Industrial
Curtailment
X X X
Rates Time-of-Use Opt-in X X X X X X
Time-of-Use Opt-out X X X X X X
Variable Peak Pricing X X X X X X

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Chapter 6: Demand Response

Avista Corp 2021 Electric IRP 6-5
Demand Response Program Descriptions

Direct Load Control
A DLC program targeting Avista’s Residential and General Service customers in Idaho
and Washington would directly control electric space heating load in winter, space-
cooling load in the summer, and water heating load throughout the year with a load
control switch or programmable thermostat. Central electric furnaces, heat pumps and
central air-conditioners would cycle on and off during high-load events. Water heaters
would completely turn off during the DR event period. Tank style, domestic electric
water heaters of all sizes are eligible for control. Smart appliances included in the
analysis include refrigerators, clothes washers and dryers. Typically, DLC programs
take five years to ramp up to maximum participation levels.

Third Party Contracts - Firm Curtailment
Customers participating in a firm curtailment program agree to reduce demand by a
specific amount or to a pre-specified consumption level during the event in exchange
for fixed incentive payments. Customers receive payments while participating in the
program even if they never receive a load curtailment request while enrolled in the
program. The capacity payment typically varies with the firm reliability-commitment
level. In addition to fixed capacity payments, participants receive compensation for
reduced energy consumption. Because the program includes a contractual agreement
for a specific level of load reduction, enrolled loads have the potential to replace a firm
generation resource. Financial penalties are a possible component of a firm
curtailment program.

Customers with maximum demand greater than 200 kW and operational flexibility are
attractive candidates for firm curtailment programs. Examples of customer segments
with high participation possibilities include large retail establishments, grocery chains,
large offices, refrigerated warehouses, water- and wastewater-treatment plants and
industries with process storage (e.g. pulp and paper, cement manufacturing).
Customers with operations requiring continuous processes, or with relatively inflexible
obligations, such as schools and hospitals, generally are not good candidates for
curtailment programs.

Third parties often administer firm curtailment programs and are responsible for all
aspects of program implementation, including program marketing and outreach,
customer recruitment, technology installation and incentive payments. Avista could
also contract with a third party to deliver a fixed amount of capacity reduction for a
specified number of events over a certain specified timeframe. The contracted
capacity reduction and the actual energy reduction during DR events is the basis of
payment to the third-party administrator.

Thermal Energy Storage
Thermal energy storage technologies draw electricity during low demand periods and
store it as ice sealed inside the unit. A variable speed fan can automatically circulate the
cool air throughout a room using the stored energy (ice) rather than having to draw energy
from the grid during peak times to chill the air.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Chapter 6: Demand Response

Avista Corp 2021 Electric IRP 6-6
This emerging technology has been primarily used in non-residential buildings and
applications but may have the potential to be used in the future for residential applications
as the technology advances.

Battery Energy Storage
Battery energy storage technologies draw electricity during low demand periods and store
it for use later during peak times. This study assumes energy is stored using
electrochemical processes as found with lithium-ion battery equipment.

Behavioral
A behavioral program is a voluntary reduction in response to digital behavioral
messaging. These programs typically occur in conjunction with energy efficiency
behavioral reporting programs and communicate the request to customers to reduce
usage via text or email messages. AMI technology is needed to evaluate and measure
the impact of the program for events.

Ancillary Services
For DR providing ancillary (spinning, non-spinning, regulation) and load following
services, loads need to respond within a very short notification period, typically less than
10 minutes. These “Fast DR” programs providing load following services are relevant for
integrating intermittent renewable resources such a solar and wind. A subset of
participants from other DR programs including Smart Thermostats – Heating/Cooling,
DLC Water Heating, CTA-2045 Water Heating, Electric Vehicle Charging and Battery
Energy Storage could supply these services if called upon.

Time of Use Rates (Opt-In or Opt-Out)
A Time of Use (TOU) rate is a time-varying rate. Relative to a revenue-equivalent flat rate,
the rate during on-peak hours is higher, while the rate during off-peak hours is lower. This
provides customers with an incentive to shift consumption out of the higher-price on-peak
hours to the lower cost off-peak hours. TOU is not a demand-response option, per se, but
rather a permanent load shifting opportunity. Large price differentials are generally more
effective than smaller differentials for TOU programs.

The DR study considered two types of TOU pricing options. In an opt-in rate, participants
voluntarily enroll in the rate. An opt-out rate places all customers on the time-varying rate,
but they may opt-out and select another rate later.

Variable Peak Pricing
Similar to TOU pricing, variable peak pricing changes prices daily to reflect system
conditions and costs. Under a variable peak pricing program, on-peak prices for each
weekday are made available the previous day. Variable peak pricing bills customers for
their actual consumption during the billing cycle at these prices. Over time, establishment
of event-trigger criteria enables customers to anticipate events based on extreme weather
or other factors. System contingencies and emergency needs are good candidates for
variable peak pricing events. Variable peak pricing program participants are required to
be enrolled in a TOU rate option.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Chapter 6: Demand Response

Avista Corp 2021 Electric IRP 6-7
Large Industrial Curtailment
This IRP includes a 25 MW large industrial curtailment program to approximate the DR
potential with one of Avista’s larger industrial customers. Program sizes are likely to be
around 25 MW, but there is the potential for additional load reduction depending on
customers’ flexibility. The concept of this program is to develop parameters for customer
curtailment and compensate customers with a fixed or per curtailment amount.

For additional detail on the various DR program characteristics, see chapter 6 of the 2020
CPA. AEG’s DR potential assessment is also included in Appendix E.

Demand Response Program Participation
The steady-state participation assumptions rely on an extensive database of existing
program information and insights from market research results and represent “best-
practices” estimates for participation in these programs. The industry commonly
follows this approach for arriving at achievable potential estimates. However, practical
implementation experience suggests that uncertainties in factors such as market
conditions, regulatory climate, economic environment and customer sentiments are
likely to influence customer participation in DR programs.

Once initiated, DR options require time to ramp up to a steady state because of the
time needed for customer education, outreach and recruitment; in addition to the
physical implementation and installation of any hardware, software, telemetry or other
enabling equipment. DR programs included in the AEG study have ramp rates
generally with a three- to five-year timeframe before reaching a steady state.

Table 6.2 shows the steady-state participation rate assumptions for each DR program
option. Space cooling is split between DLC Central AC and Smart Thermostat options.

Table 6.2: DR Program Steady-State Participation Rates (% of eligible customers)

DR Program Residential
Service Service/
Small
General
Service
Large
General
Direct Load Control (DLC) of central AC 10% 10% - -
DLC of domestic hot water heaters (DHW) 15% 5% - -
Smart Thermostats DLC Heating 5% 3% - -
CTA-2045 hot water heaters 50% 50% - -
Smart Thermostats DLC Cooling 20% 20% - -
Smart Appliances DLC 5% 5% - -
Third Party Contracts - 15% 22% 21%
Electric Vehicle DLC Smart Chargers 25% - - -
Time-of-Use Pricing Opt-in 13% 13% 13% 13%
Time-of-Use Pricing Opt-out 74% 74% 74% 74%
Variable Peak Pricing 25% 25% 25% 25%
Thermal Energy Storage - 0.5% 1.5% 1.5%
Battery Energy Storage 0.5% 0.5% 0.5% 0.5%
Behavioral 20% - - -
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Chapter 6: Demand Response

Avista Corp 2021 Electric IRP 6-8
Demand Response Potential and Cost Assumptions
Each DR program used in this evaluation was assigned an average load reduction per
participant per event, an estimated duration of each event, and a total number of event
hours per year. Costs were also assigned to each DR program for annual marketing,
recruitment, incentives, program development and administrative support. These
resulted in potential demand savings and total cost estimates for each program
independently or on a standalone basis.

This approach does not account for participation overlaps among DR options targeted
at the same customer segment and therefore savings and cost results for individual
DR programs are not additive. The standalone analysis results provide a comparative
assessment of individual DR program demand savings and costs and are useful for
selecting programs for a DR portfolio.

If Avista offers more than one program, then the potential for double counting exists.
To address this possibility, a participation hierarchy was assumed and defines the
order customers take the programs for an integrated approach. These savings and
costs results were then used in Avista’s modeling. For additional detail on DR resource
assumptions used in developing potential savings and cost results, see Chapter 6 of
the 2020 CPA.

Achievable Potential Estimates
Two DR potential programs for TOU were reviewed for Avista’s load. The first is Time of
Use (TOU) rates as opt-in. This means customers sign up for a time-based rate schedule
versus the second potential study where customers must opt out of the new potential rate
schedule. Because TOU rates change customer behavior, the amount of DR savings
differs between how many customers have this rate schedule. For this IRP, the potential
study results use the TOU Opt-in scenario in the integrated savings and costs since it is
more likely Avista may offer a TOU Opt-in program rather than a TOU Opt-out program
should a pricing program be implemented. Figures 6.2 and 6.3 show demand savings
from all available individual DR programs from DR options in Avista’s Idaho and
Washington service territories.

Additional detail for these programs including specific cost and savings is included in
Tables 6.3 and 6.4. The cost of the programs within these tables represent the on-going
operations and capital cost required to start and maintain these programs. The capital
costs are amortized and recovered over a 10-year period. The costs included are the first
10 years levelized as if the program begins in 2022. These tables include the estimated
potential megawatt savings for 2031 and 2045. These estimates are the expected amount
of demand reduction from all program participants. Although, Avista will require a higher
amount of contracted load to achieve these savings. The Maximum Impact Percentage
column is the amount of additional MW shown as a percentage of additional load required
to meet the expected demand reduction. For example, to achieve the 4.3 MW of reduction
from Time of Use rates would require nearly three times the amount of capacity under
contract.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 117 of 317
Chapter 6: Demand Response

Avista Corp 2021 Electric IRP 6-9
Winter Demand Response Savings Potential
Key findings:
 The highest potential option is the CTA-2045 WH water heater program which
is expected to reach a savings potential of 48.9 MW by 2045.
 The next three biggest potential DR options in winter include DLC Electric
Vehicle Charging (30.2 MW in 2045), Third Party Contracts (21.9 MW) and
Variable Peak Pricing Rates (12.5 MW).
 Since most of the participants are likely to be on the VPP rate in the TOU Opt-
in scenario, the TOU potential (4.3 MW in 2045) is significantly lower than in the
TOU Opt-out case where 17.8 MW of winter peak load would be reduced by this
program.
 The total potential savings in the winter TOU Opt-in scenario are expected to
increase from 9.3 MW in 2022 to 145 MW by 2045. The respective increase in
the percentage of system peak goes from 0.7 percent in 2022 to 10.0 percent
by 2045.

Figure 6.2: Demand Response Achievable Potential (Winter MW)

Winter Demand Response Costs
In addition to levelized costs, 2031 savings potential from DR options are represented for
reference.

Key findings:
 The third-party contracts option delivers the highest savings in 2031 at
approximately $96/kW-year cost. Capacity-based and energy-based payments to
the third-party constitutes the major cost component for this option. All O&M and
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Large C&I
CTA-2045 WH
DLC Water Heating
DLC Electric Vehicle Charging
Third Party Contracts
DLC Smart Thermostats - Heating
Variable Peak Pricing Rates
Battery Energy Storage
Time-of-Use Opt-in
DLC Smart Appliances
Behavioral
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 118 of 317
Chapter 6: Demand Response

Avista Corp 2021 Electric IRP 6-10
administrative costs are expected to be incurred by the representative third-party
contractor.
 The Variable Peak Pricing (VPP) option has the lowest levelized cost among all the
DR options. It delivers 15.5 MW of savings in 2031 at $33/kW-year system wide.
Enabling technology purchase and installation costs for enhancing customer
response is a large part of VPP deployment costs.

Table 6.3: DR Program Costs and Potential – Winter TOU Opt-In

DR Option Levelized
$/kW
(2022-
System
Winter
Potential
System
Winter
Potential
Maximum
Impact
Potential
Battery Energy Storage $483 2.8 5.6 100%
Behavioral $210 2.2 1.7 101%
CTA-2045 WH $122 17.6 48.9 144%
DLC Electric Vehicle Charging $353 3.9 30.2 137%
DLC Smart Appliances $295 3.2 3.7 101%
DLC Smart Thermostats - Heating $92 9.5 10.9 286%
DLC Water Heating $213 5.5 5.5 144%
Third Party Contracts $96 21.9 21.9 101%
Time-of-Use Opt-in $83 5.2 4.3 300%
Variable Peak Pricing Rates $33 15.5 12.5 282%

Summer Demand Response Savings Potential
Key findings:
 The highest potential option is DLC Smart Thermostats, which is expected to reach
savings potential of 61 MW by 2045.
 The next two biggest potential options in summer include CTA-2045 WH (48.9 MW
in 2045), DLC Electric Vehicle Charging (30.2 MW) and DLC Central AC (24.5
MW).
 Two space cooling options- DLC Smart Thermostat and DLC Central AC – are
expected to contribute a combined 86 MW by 2045.
 Total potential savings in the summer TOU Opt-in scenario are expected to
increase from 11.3 MW in 2022 to 220 MW by 2045. The respective increase in the
percentage of system peak increases from 0.8 percent in 2022 to 15.4 percent by
2045.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 119 of 317
Chapter 6: Demand Response

Avista Corp 2021 Electric IRP 6-11
Figure 6.3: Demand Response Achievable Potential (Summer MW)

Summer Demand Response Costs
In addition to levelized costs, 2031 savings potential from DR options are represented for
reference.

Summer DR Key findings:
 DLC Smart Thermostats deliver the highest savings in 2031 (28.68 MW) at
approximately $159/kW-year. Capacity-based and energy-based payments to the
third-party constitutes the major cost component for this option. All O&M and
administrative costs are expected to be incurred by the representative third-party
contractor.
 The Variable Peak Pricing (VPP) option has the lowest levelized cost among all
the DR options. It delivers 15.5 MW of savings in 2031 at $33/kW-year system
wide. Enabling technology purchase and installation costs for enhancing
customer response is a large part of VPP deployment costs.

0
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200
250
2022 2023 2025 2035 2045
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Large C&ICTA-2045 WHDLC Water HeatingDLC Electric Vehicle ChargingThird Party ContractsDLC Central ACDLC Smart Thermostats - CoolingThermal Energy StorageVariable Peak Pricing RatesBattery Energy StorageTime-of-Use Opt-inDLC Smart AppliancesBehavioral
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 120 of 317
Chapter 6: Demand Response

Avista Corp 2021 Electric IRP 6-12
Table 6.4: DR Program Costs and Potential – Summer TOU Opt-In

DR Option Levelized
$/kW
(2022-
Summer
Potential
Summer
Potential
Impact
Potential
Battery Energy Storage $483 2.8 5.6 100%
Behavioral $210 2.2 1.7 101%
CTA-2045 WH $122 17.6 48.9 144%
DLC Central AC $83 12.7 24.5 492%
DLC Electric Vehicle Charging $353 3.9 30.2 137%
DLC Smart Appliances $295 3.2 3.7 101%
DLC Smart Thermostats - Cooling $159 28.7 61.0 494%
DLC Water Heating $213 5.5 5.5 144%
Thermal Energy Storage $800 0.7 0.6 101%
Third Party Contracts $96 21.9 21.9 101%
Time-of-Use Opt-in $73 5.2 4.3 300%
Variable Peak Pricing Rates $33 15.5 12.5 274%

The value of these programs in meeting Avista’s capacity needs is calculated in the Avista
IRP modeling process using the magnitude of DR program potential and the estimated
costs provided by AEG. In addition, Avista assigns a DR peak credit as described below.

Demand Response Peak Credit
For reliability planning, Avista translates the peak savings identified by AEG into a peak
credit, meaning the percentage of the capacity each option contributes to meeting Avista
reliability criteria in peak load periods. An Effective Load Carrying Capability (ELCC)
analysis is performed to determine the peak credit. Refer to Chapter 9 for a more in-depth
discussion of Avista’s ELCC methods. A DR program’s assigned peak credit will differ
depending on its duration. Programs interrupting loads for longer periods will receive
larger peak credits, but the peak credit depends on if there is a “snap back” effect when
the DR event is over. Loads without a snap back effect shed load permanently whereas
loads exhibiting the snap back effect are higher later due to recovery from the earlier
reduction from the DR program. Avista only had adequate time to conduct generic DR
programs assuming up to eight hours of load reduction. This analysis results in a 60
percent peak credit for a continuous 8-hour DR load reduction. Avista concludes this is a
result of limited energy reduction when Avista needs winter energy in addition to winter
peak reductions. Avista will need to conduct further DR peak credit analysis in future
IRPs.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 121 of 317
7. Long-Term Position
This chapter describes the analytical framework used to develop Avista’s net load and
resource position. It describes reserve margins held to meet peak loads, risk-planning
metrics used to meet hydro variability and plans to meet renewable goals set by
Washington’s Energy Independence Act (EIA) and the Clean Energy Transformation Act (CETA).

Avista has unique attributes affecting its ability to meet peak load requirements. While it
connects to several neighboring utility systems across its large service territory, it comprises only 5 percent of the total Northwest regional load. Annual peaks can occur
either in the winter or in the summer; but Avista is still winter peaking on a planning basis
due to periods of extreme cold weather conditions. The winter peaks generally occur in
December or January but may also occur in November or February. As described in Chapter 4 – Existing Supply Resources, Avista’s resource mix contains roughly equal amounts of hydro and thermal generation. Hydro resources meet most of Avista’s
flexibility requirements needed for load and intermittent generation, though thermal
generation is playing a larger role as load growth and intermittent generation increase
flexibility requirements.

Reserve Margins
Planning reserves accommodate situations when load exceeds and/or resource output
falls below expectations due to adverse weather, forced outages, poor water conditions
or other unplanned events. Reserve margins, on average, increase customer rates when
compared to resource portfolios without reserves because of the cost of carrying rarely used generating capacity. Reserve resources have the physical capability to generate electricity, but most have high operating costs that limit normal dispatch and revenue.

There is no industry standard reserve margin level, as it is difficult to enforce
standardization across systems with varying resource mixes, system sizes and transmission interconnections. NERC defines reserve margins as 15 percent for
predominately thermal systems and 10 percent for predominately hydro systems1, but
does not provide an estimate for energy-limited hydro systems like Avista.
Since Avista and the region’s hydro system is energy constrained, the 10 or 15 percent
metrics suggested by NERC do not adequately account for the Company’s load and
1 http://www.nerc.com/pa/RAPA/ri/Pages/PlanningReserveMargin.aspx.
Section Highlights
• Avista’s first long-term capacity deficit net of energy efficiency is in 2026 at 12
MW, increasing to 301 MW in 2027; the first energy deficit is also in 2026.
• By 2022, clean resource generation meets 75 percent of retail sales.
• The regional resource adequacy situation is at risk due to planned coal plant
retirements and load growth without the addition of new capacity resources.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 122 of 317
resource variations. Beyond planning margins defined by NERC, a utility must maintain operating reserves to cover generator forced outages to maintain grid stability. Avista
includes operating reserves in addition to a planning margin. Per Western Electric
Coordinating Council (WECC) requirements, Avista must maintain 3 percent for balancing
of area load and 3 percent for on-line balancing area generation. Within this quantity, 24 megawatts must also qualify as Frequency Response Reserve (FRR). Avista must also maintain reserves to meet load following and regulation requirements of within-hour load
and generation variability equivalent to 16 MW at the peak hour.

Avista’s planning margin in the 2020 IRP was 16 percent2 in the winter (October through April) and 7 percent in the summer (May through September). Adding operating and load
following reserves increased the totals to 24.6 and 15.6 percent, respectively. This was a
result of a study of Avista resources and loads using 1,000 simulations varying weather
for loads and thermal generation capability, forced outage rates on generation, water
conditions for hydro plants and wind generation. The reserve levels ensured Avista’s system could meet all expected load in 95 percent of the simulations, a 5 percent loss of
load probability (LOLP).

The northwest region began investigating a resource adequacy program in 2019. As part of this effort, a consultant (E3) developed tools to identify planning margins each utility should be meeting absent a regional resource adequacy program and planning margins
with a resource adequacy program. Avista used this analysis to validate its current
planning margin. This independent analysis suggests utilities use a 1-in-2 load forecast,
as Avista does, a 16 percent planning margin on this load forecast, and then derate resources using a peak credit to account for forced outages and energy limitations. The
only difference between the E3 methodology and Avista’s current method is Avista
assumes a higher planning reserve margin to account for operating reserves rather than
derating its facility’s peak credit. A comparison between the two methods is shown in
Figure 7.1. Avista’s method shows the system longer in the early years, but shorter in the winter and nearly the same in the summer by the end of the study. Given Avista peak
load is near 1,800 MW, the differences between the two methods are relatively small.

The intent of the proposed Regional Resource Adequacy Program is to allow for lower
planning margins to reduce customer cost while ensuring the region is building adequate resources to meet expected load plus contingencies. Avista conducted a scenario to show
the financial benefit of this program in Chapter 12. Given this information, Avista’s
planning margin criteria is within standard utility practice; but it is at risk as regional market
power may not be available in quantities required if other utilities do not also provide their share of capacity to the region. Avista models up to 330 MW of market reliance to satisfy its 5 percent LOLP.

2 Avista’s PRS used an 18 percent planning margin to overcome peak credits for storage and intermittent
resources that were too low.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 123 of 317
Figure 7.1: Stand Alone Northwest Utility vs. Avista’s L&R Methodology
Balancing Loads and Resources
The single-hour future load and resource projection is a simple method to identify
shortages when adjusted by a planning reserve margin. It is used in Avista’s resource selection model, but also to provide a review of system resource adequacy. The one-hour
peak does not consider sustained peaking events where Avista’s hydro system or a future
storage system cannot continually deliver energy over multiple peak hours, such as a
week of extreme cold weather. To ensure reliance on a one-hour metric does not
compromise system reliability, Avista conducts a detailed hourly reliability study to validate whether the planning margin also satisfies other potential resource shortfalls.
This analysis informs the creation of a planning reserve margin to include in the single
peak hour analysis. Avista’s single hour peak winter load and resource position are shown
in Figure 7.2. In this illustration, Avista includes Colstrip Units 3 and 4 through the end of
2025, though Avista is uncertain when Colstrip will exit its portfolio under the current ownership agreement. With this assumption, the first significant winter capacity deficit
occurs in January 2026 with a 12 MW deficit and quickly escalates to 301 MW in 2027
after the Lancaster contract expires in October 2026.
Avista plans to meet summer peak load with a smaller planning margin than in the winter.
Summer months include operating reserve and regulation obligations in addition to a 7
percent planning margin (see Figure 7.3). Avista uses a smaller planning margin in the
summer months due to less variation in summer peak load levels and reliability planning
analysis showing no summer adequacy issues when Avista addresses its larger winter peak requirements. Market purchases should satisfy any weather-induced load variation
or generation forced outage that otherwise would be included in the planning margin as
is the case with the higher winter planning margin. In this comparison, Avista’s first
summer deficit occurs in 2027 at 171 MW.

Winter Summer
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 124 of 317
Figure 7.2: Winter One-Hour Peak Capacity Load and Resources Balance

Figure 7.3: Summer One-Hour Peak Capacity Load and Resources Balance

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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 125 of 317
Energy Planning
For energy planning, resources must be adequate to meet customer requirements even when loads are high for extended periods, or sustained outages limit the contribution of
one or more resources. Where generation capability is inadequate to meet these
variations, customers and the utility must rely on the short-term electricity market. In
addition to load variability, Avista holds energy-planning margins for variations in month-
to-month hydro generation.
As with capacity planning, there are no defined methods for establishing an energy-
planning margin. Many utilities in the Northwest base their energy planning margins on
the amount of energy available during the “critical water” period of 1936/37.3 The critical water year of 1936/37 is low on an annual basis, but it does not represent a low water condition in every month of that hydro year. The IRP could target resource development
to reach a 99 percent confidence level to deliver energy to its customers to significantly
decrease the frequency of market purchases. However, this strategy requires
investments in approximately 200 MW of generation in addition to the capacity planning margins included in the Expected Case. Investments to support this high level of reliability
would increase pressure on retail rates for a modest reliability benefit. Avista plans to the
90th percentile for hydro generation. Using this metric, there is a one-in-ten chance of
needing to purchase energy from the market in any given month over the IRP timeframe
due solely to a shortage of available generation from its hydro resources. Avista uses the annual average of the monthly position shown in Figure 7.4 to set a minimum energy
acquisition target.
Figure 7.4: Annual Average Energy Load and Resources

3 The 1936/37 critical water year represents the lowest historical generation level in the streamflow record.
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2,000
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3,000
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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 126 of 317
State Level Planning
Avista separates capacity and energy targets in the 2021 IRP between Idaho and
Washington. This split ensures Avista acquires new resources to meet specific state goals
when needed and allows for tracking of costs to be assigned to each state as necessary to meet its goals. This methodology extends to reliability targets. Avista split loads and
costs for resources using the Production-Transportation ratio (PT ratio) for resources
planned for use by both states. The PT ratio is approximately 65 percent Washington and
35 percent Idaho. The method excludes a large PURPA facility and its load which are
directly assigned to Idaho. All PURPA generation is assigned to the state where its contract was approved. The portfolios identified in Chapters 11 and 12 show how each
resource is assigned to either or both states. Figure 7.5 shows each state’s position for
winter, summer and annual energy. The state level data follows the system level data as
presented earlier, though a small difference exists due to the unique arrangement of the
Idaho large load and associated PURPA generation identified above.
Figure 7.5: State Level Load and Resource Position by State

2021 IRP Resource Adequacy Assessment
Serving customers with an adequate resource supply is challenging without new capacity resources. Table 7.1 shows the probability of load loss in each month absent resource
additions based on 1,000 simulations. Each “simulation” not able to serve all load with
existing resources plus up to 330 MW of market purchases expected to be available to
Avista is considered a loss of load event. This methodology is termed a Loss of Load Probability (LOLP) analysis. With Colstrip included through 2025, Avista is resource adequate, but without the two coal units the Company exceeds the 5 percent LOLP limit.
The table shows a 21 percent probability of lost load in 2030 to represent the additional
loss of Lancaster in 2026. By 2040, this shortfall increases to 81.4 percent.
-300
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-100
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300
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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 127 of 317
Table 7.1: LOLP Reliability Study Results without New Resources

Jan 0.6% 2.7% 10.5% 32.7%
Feb 0.1% 0.6% 4.2% 15.0%
Mar 0.0% 0.0% 0.5% 2.9%
Apr 0.0% 0.0% 0.0% 0.0%
May 0.0% 0.0% 0.0% 0.0%
Jun 0.0% 0.0% 0.0% 0.1%
Jul 0.0% 0.3% 1.7% 33.0%
Aug 0.0% 0.1% 0.6% 30.5%
Sep 0.0% 0.0% 0.0% 0.9%
Oct 0.0% 0.0% 0.0% 0.5%
Nov 0.0% 0.0% 0.7% 5.0%
Dec 0.8% 3.2% 7.1% 17.1%
Annual 1.4% 6.3% 21.2% 81.4%

To resolve the lost load, the IRP identifies the addition of 333 MW of winter capability, or a 16 percent planning margin, would reduce the LOLP to 5 percent on an annual average basis by 2030. This analysis assumes Avista could acquire up to 500 MW from the market
in non-regionally stressed hours and 330 MW in regionally stressed hours recognizing
that the market is not unlimited. Regionally stressed hours occur when Avista’s average
daily temperature exceeds the 99th percentile. This happens in days where the average temperature is 2 degrees Fahrenheit or lower in the winter, and 83 degrees or higher in
the summer. Placing limits on market reliance is a difficult exercise and may seem
arbitrary given the difficultly in its quantification due to regional load diversity and the
surplus capability of each regional utility or independent power producer. Avista revised
its market reliance in this IRP up to 330 MW from 250 MW used in previous IRPs. This market assumption change ensures the 16 percent winter planning margin achieves a 5
percent LOLP. While this change assumes greater market reliance, it also results in lower
customer cost. The change is informed by regional work discussed in other parts of this
report indicating that higher market reliance is possible under a regional capacity planning effort.
Resource Adequacy Risk Assessment
Future planning of resource adequacy requires consideration of many risks. Avista is
utilizing the risks identified by the November 2020 paper Implications of Regional
Resource Adequacy Program on Utility Integrated Resource Planning4 to detail how
Avista manages these risks. While Avista’s identified 2026 resource deficit is not likely to
change since the deficit is driven by the expiration of a purchase power agreement, the risks outlined below will impact the ultimate resource need.

4 Implications of a regional resource adequacy program on utility integrated resource planning
https://www.westernenergyboard.org/wp-content/uploads/11-2020-LBNL-WIEB-regional-resource-
adequency-and-utility-integrated-resource-planning-final-paper.pdf.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 128 of 317
Peak Demand Forecast
Avista uses a 1--in-2 peak load forecast, meaning half of the time the load will be above and half the time load will be below the peak forecast. The forecast is based on historical
weather conditions. These same weather conditions are used in reliability planning that
drives the planning margin used to account for these risks. While weather is considered
in the unknown nature of future loads, there are also other load risks the Company
considers in scenario analysis. These potential changes are from economic impacts, electrification and increased customer owned generation. Avista conducted analysis on
portfolio changes for these risks in Chapter 12 of this IRP to understand the implication
to load and the resources needed.
Demand-Side Resource Contribution Avista includes demand-side resources as options when determining the amount and
type of resources needed to meet future demand, but demand side resources may also
impact the net demand of the system prior to this inclusion. For example, roof top solar
may reduce Avista’s summer energy needs, but have limited impact on winter loads. To address this risk, Avista includes an estimate of new customer owned generation in its
load forecast and performed scenario analysis in prior IRPs. The greatest risk to
uncertainty regarding demand-side resources is whether they will impact winter peak load
requirements and given today, most additions are solar, this risk is low. If customers begin
to install a winter load impacting resources, Avista will need to reconsider the risk at that time.

Power Plant Retirement
To address the uncertainty of power plant retirements, Avista conducted two scenarios to understand the reliability implications of Colstrip exiting the portfolio along with including other potential resource retirements in long run reliability studies.

Renewable Contribution
Increasing renewable penetrations will impact the reliability of the power system if utilities estimate their contributions too high. Avista found in the 2020 IRP it needed additional
resources to maintain the 5 percent LOLP when relying on renewable resources to meet
its peak loads. This concept can also be related to the Peak Credit analysis or Effective
Load Carrying Capability (ELCC) analysis discussed in Chapter 9. The issue is if
increasingly correlated intermittent resources are added to the system, the value they contribute to reliability “peak credit” declines. Other ELCC studies have shown this same
effect5. Avista found this was an issue in the last IRP for Montana wind and conducted
further analysis in this IRP to have a reducing peak credit as more resources are added
to the system. While this is an issue for other resources evaluated, the Montana wind resource is more impactful due to the high peak credit it receives compared to other
resources.

Storage Efficiency
Avista sees two risks for storage efficiency. The first risk is similar to the renewable contribution described above where short duration resources may help reliability in small
5 Such as E3’s Resource Adequacy in the Pacific Northwest Study.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 129 of 317
increments, but the reliability benefit is reduced as more storage is added to the system
due to the need to recharge the storage device after use. The second risk of storage is
the efficiency to recharge the device. Not all storage technologies have the same
recharging ability based on energy losses and time to recharge; therefore, each of these
considerations should be included in determining each device’s peak credit. Avista has begun this analysis as shown in Chapter 9, but due to the multitude of storage
configurations and technologies, this analysis will be an ongoing exercise.

Market Availability
Avista found market availability to be the greatest risk in resource adequacy absent a resource adequacy market or program. As described earlier, Avista limits market
purchases to 330 MW in critical time periods to avoid placing significant reliance on a
market that may or may not have enough resources available. Part of this risk is not only
resource availability, but also load diversity with the region as loads are not perfectly
correlated across the northwest.
Avista conducted an analysis to understand the benefits of regional load diversity, as
shown in Figure 7.6. Regional load is compared to Avista Balancing Authority (BA) load
for the top 98th percentile daily peak loads since 2010. This data showed an increasing
relationship between Avista load and regional loads, but the R-squared is low at 36 percent, indicating a weak correlation. In addition, when the maximum regional load was
nearly 34,884 MW, Avista’s BA load was approximately 10 percent below its maximum.
Avista found in these top load hours the regional load range is 3,835 MW. When
considering only Avista’s 99th percentile load and above the regional range is 3,027 MW.
This analysis illustrates the current load diversity in the region and indicates Avista can rely on market purchases for a share of its peak load needs if the region has adequate
resources to meet the regional coincident peak load.

The issues presented here show why the region is pursuing a resource adequacy
program to ensure the region has adequate resource capability and that each utility is providing its fair share of capacity. Another benefit from an IRP planning perspective is
the identification of a clear and regionally consistent planning margin requirement and
peak credits.
Resource Acquisition When utilities have a need for new supply-side resources, the utility has two paths to add
generation. The utility can add existing generation owned by other utilities or independent
power producers if available or it can acquire new resources through either a PPA or
ownership. Given the timelines for construction and permitting, Avista plans to issue RFPs
to acquire new resources with enough time to overcome any potential obstacles of new generation construction and allow for the potential purchase of existing generation with
prior off-taker agreements ending. The results of an RFP may cause timing differences
between the forecasted need and the acquisition date. While acquiring a resource ahead
of need may cause rate pressure, it may also eliminate risks such as construction delays.
If the existing resource is available after the need, the Company will have to find a short-term solution to meet the resource deficit prior to a new resource becoming available.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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This short-term solution may increase risk to customers but may be at a lower cost alternative then building resources at the time of need.

Figure 7.6: Avista versus Regional Loads (98th percentile)
Washington State Renewable Portfolio Standard
Washington’s EIA promotes the development of regional renewable energy by requiring
utilities with more than 25,000 customers to source 15 percent of their energy from qualified renewables by 2020. Utilities must also acquire all cost-effective conservation
as explained in Chapter 5 – Energy Efficiency. In 2011, Avista signed a 30-year PPA with
Palouse Wind to help meet the EIA goal. In 2012, an amendment to the EIA allowed
Avista’s Kettle Falls project to qualify toward the EIA goals beginning in 2016. More
recently Avista acquired the Rattlesnake Flat wind project and Adams Nielson Solar6 project, both of which qualify for EIA and CETA compliance.

Table 7.2 shows the forecasted renewable energy credits (RECs)7 Avista needs to meet
the EIA renewable requirement and the amount of qualifying resources already in Avista’s generation portfolio. This table does not reflect the additional flexibility available for the
REC banking provision in the EIA. Avista uses this banking flexibility as needed to
6 Adams Neilson will be used for the EIA after the Solar Select program ends.
7 These RECs are qualifying RECs within Avista’s system. For state compliance purposes the Company may transfer RECs between a state’s allocation shares at market prices. Avista may also sell excess RECs
to reduce customer rates.
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manage variation in renewable generation. After 2030, the renewable energy obligation to meet the EIA is met, as long as Avista is compliant with the requirements of CETA.

Table 7.2: Washington State EIA Compliance Position Prior to REC Banking (aMW)
2022 2025 2030
Net Renewable Goal
Other Available RECs
Net Renewable Position (before rollover RECs) 54.1 51.2 55.4
Washington State Clean Energy Transformation Act (CETA)
Washington State’s CETA requires serving 100 percent of state retail sales with clean
energy by 2045. In 2030, up to 20 percent of this clean energy may use an alternative
compliance mechanism to satisfy the requirement. Since final rules were not in place to define all potential programs qualifying for this designation except for unbundled RECs, Avista did not model all alternative compliance options for this plan. For this IRP, Avista
made assumptions on how compliance would work and how to manage the renewable
energy for a multi-state utility. The following is a list of the assumptions included to
develop the clean energy need assessment in Figure 7.7.
• Qualifying clean is determined by procurement and delivery of clean energy to
Avista’s system for all years.
• The clean energy goal is applied to retail sales less in-state PURPA generation
constructed prior to 2019 plus voluntary customer programs such as Solar Select.
• Customer voluntary REC programs, such Avista’s My Clean Energy™ program,
do not qualify toward the CETA standard.
• Interim targets of 80 percent of net Washington retail sales are met with clean
energy and unbundled RECs in 2022 and 2023, 85 percent in 2024 and 2025, 90
percent in 2026 and 2027, 95 percent in 2028 and 2029, and 100 percent clean
energy in 2030 with an allowance of up 20 percent from unbundled RECs .
• All existing clean energy resources within the Avista portfolio are allocated
between Idaho and Washington customers using the PT ratio.
8 Rattlesnake Flat wind may also qualify for the apprentice credits, creating a 20 percent adder to the REC
amount available for EIA compliance. This table does not include the 20 percent adder.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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• Avista may transfer qualifying non-hydro clean energy generated for Idaho loads to Washington if needed by compensating Idaho at a forecasted REC price of
$7.50 per MWh escalating at 5 percent per year9.
• While CETA allows for up to 20 percent of compliance from unbundled RECs in 2030, Avista intends to meet this requirement between 2030 and 2033 purchasing Avista Idaho customer’s share of the hydro system as unbundled RECs and then
up to 15 percent between 2034 and 2037, 10 percent between 2038 and 2041,
and 5 percent between 2042 and 2044.
• Avista is not planning to use Idaho’s hydro RECs prior to 2030 for planning purposes to incent clean energy acquisitions, however actual compliance may
include them due to variability in clean resource availability.
• Avista anticipates final rules regarding the “use” of clean energy for compliance purposes in late 2021. Depending upon the final adoption of the CETA rules for compliance, Avista may change its needs assessment for future IRPs accordingly.

Based on this plan of acquisition and normal water conditions, Avista has enough
qualifying resources to meet its internal 80 percent target in 2022 and 2023 but will need to acquire up to 51 aMW by 2024 and up to 132 aMW of clean energy by 2029. The 2045 goal will require 326 aMW of additional clean energy.

Figure 7.7: Washington State CETA Compliance Position

9 In operations, transfers of RECs between states shall be market price based. Avista uses $7.50 per MWh for this IRP based on transactions Avista has made at the time of the development of the IRP.
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Avista’s Company-Wide Clean Energy Goal
Avista set a corporate goal to serve all retail customers with 100 percent carbon neutral
energy by 2027 and deliver 100 percent clean energy by 2045 for the entire system while maintaining reliability and affordability for its customers. From a resource planning
perspective, the 2027 goal entails ownership or control of renewable resources or RECs
equal to retail sales by 2027 and phasing out all fossil fuel producing generation by 2045.
Each of these goals must carefully consider cost implications and technical feasibility
balanced to ensure customer affordability. Avista is still working out the details of what would be acceptable to customers regarding affordability; whether this is a dollar
threshold, a percentage increase or an energy burden level for different customer groups.
Avista will seek customer input on these and other issues as described in Chapter 13 –
Energy Equity. This section discusses the amount of energy and capacity necessary to
meet the Company’s system-wide clean energy goals. By 2022, Avista will have enough clean generation over the course of the year to meet 75 percent of retail sales. Avista
would need to acquire an additional 318 aMW of clean energy or RECs to achieve its
2027 goal. The clean energy deficit grows to nearly 520 aMW by 2045. In addition to the
additional clean energy need in 2045, the Company will also need to add 659 MW of
winter capacity to meet the current resource deficiency and replace the 494 MW of remaining thermal resources providing capacity on a winter peak day for a 1,153 MW
total. This potential new capacity will need to operate in cold winters for a sustained period
to meet Avista’s 5 percent LOLP reliability threshold.
Figure 7.8: Avista Clean Energy Goal

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Regional Resource Adequacy
Avista relies on 330 MW of market power in its reliability study. If Avista chose not to rely on this level of available market power, its planning margins would need to be over 30
percent. However, Avista is not an electrical island, and other entities should be able to
assist Avista when loads peak due to load and resource diversity. Collectively, utilities
should plan as a system and optimize resources to meet regional needs to increase system reliability and minimize system costs for all customers and utilities in the region.
This may be an optimistic goal, as some utilities do not always make their excess capacity
available to the marketplace when needed to meet peak load events. To gain a better
understanding of the market and the region’s ability to provide adequate power, Avista participates in the Northwest Power and Conservation Council’s (NPCC) resource
adequacy forum. In addition to this process, Avista contributed funding for a recent
Northwest Power Pool resource adequacy study performed by the consulting firm E3.
This study provided regional resource builds and costs for future clean energy scenarios.
The last method Avista uses to review regional resource adequacy is part of its market price forecast.

Northwest Power and Conservation Council
The NPCC released its Pacific Northwest Power Supply Adequacy Assessment for 202410 on October 31, 2019. It highlights potential resource adequacy risks to the regional
power system. The NPCC estimates the regional 2021 LOLP to be 7.5 percent, exceeding
the region’s current 5 percent threshold due primarily to announced coal plant retirements
without commensurate replacement of capacity resources. The likelihood of lost load increases to 8.2 percent by 2024, equaling a regional 800 MW capacity shortage. When additional thermal resources retire in 2026, the regional LOLP increases to 17 percent.
Using the results from this study equates to a regional planning margin of 13.4 percent11.

The regional analysis also contained sensitivities on load and extra-regional imports. Table 7.3 shows the range in analysis provided by the NPCC for the regional LOLP in the
first three rows and the megawatts of required generation (or load reduction) in the bottom
three rows. This analysis shows the region is at risk without new resources unless loads
fall or the region can acquire reliable winter capacity from other regions. The import limit of 2,500 MW and medium load are the expected cases shown in bold.

10 https://www.nwcouncil.org/sites/default/files/2024%20RA%20Assessment%20Final-2019-10-31.pdf.
11 This assumes the BPA’s White Book average peak capacity for regional hydro generation and 2,500 MW
of imports.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Table 7.3: NPCC 2024 Resource Adequacy Analysis
LOLP % High Load (3% higher) 21.1 18.0 16.0 14.4 12.0
LOLP % Medium Load 12.5 10.2 6.9 5.2
LOLP % Low Load (3% lower) 7.0 5.2 4.0 3.1 2.0

Required MW High Load (3% higher 2,800 2,300 1,700 1,200 800
Required MW Medium Load 1,900 1,400 400 0
Required MW Low Load (3% lower) 900 200 0 0 0
The greatest chance of regional load loss occurs in the winter months, primarily in
January. The study found 27 percent of events occur in January and 19 percent in
December. The summer had a collective LOLP of 26 percent.
The NPCC presented its preliminary 2025 resource adequacy assessment in December 2020. This assessment included their assumptions on climate change impacts using
limited potential datasets for expected variation of load and hydro. This assessment also
included more coal retirements than in its 2024 study completed in 2019. The assessment
indicated a LOLP three times the maximum threshold (15 percent) in 2025 for the region, with summer months driving the deficits if hydro conditions increase along with lower peak
loads in the winter and higher loads in the summer along with lower generation. Avista
has concerns with the limited input data sets used to derive the range in potential climate
adjusted load and hydro conditions but agrees there are great risks for maintaining
regional resource adequacy in the future in this area.
Energy and Environmental Economics (E3) Study
Avista participated in a regional study sponsored by the Northwest Power Pool to
understand resource adequacy needs under different clean energy legislation options. This study was included as Appendix F of the 2020 IRP. The first year reviewed in the study was 2018 to test the model with the existing system. The study also reviewed 2030
and 2050 under multiple resource acquisition strategies. The footprint of this study
included the four northwest states, Wyoming and Utah. This is a larger footprint then
Avista’s traditional energy trading partners. The 2018 study determined the region meets its 5 percent LOLP with a value of 3.7 percent; but does not have enough capacity to
meet a goal of less than 2.4 outage hours per year (6.5 hours)12. E3 estimated the larger
region needs an “effective” planning reserve margin of 12 percent to meet the goal of less
than 2.4 outage hours per year, which would require an additional 1,200 MW of resources.
By 2030, the study estimates a need for an additional 5,000 MW of capacity to maintain reliability due to expected resource retirements and load growth.

Avista’s Market Study
Avista details its market price forecast in Chapter 10. It contains a forecast of the needs of the region to maintain resource adequacy and estimates generation needs using an approximation of system load and resources. It models the entire northwest as one entity
12 As discussed on page 36 of 2020 IRP Appendix F.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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and ignores potential power transfer limits within the region. The following capacity additions were required by 2030: 1,400 MW of demand response, 1,500 MW of storage,
and 2,300 MW of natural gas-fired combustion turbines. These additions are required
over and above the capacity benefits included for the wind and solar required to meet
state clean energy goals. Although given transfer limitations the actual required new
generation is likely to be higher.
Regional Resource Adequacy Conclusions
Avista is concerned the region is not adding enough capacity resources needed to
maintain regional resource adequacy due to resource retirements, increases in
intermittent resources and load growth. While Avista’s resource plan shows significant planning margin requirements meeting standard utility practice, these requirements may
not be enough to provide certainty for Avista’s customers if the other regional utilities do
not also add new capacity to maintain higher planning margins.

Avista is in a good current position since the Company is long capacity and exceeds its planning margin requirements through 2025. After 2025, Avista and many other regional
utilities must acquire new dependable capacity resources to ensure customers have
adequate power to sustain both extended cold winter and hot summer periods. Given the
concern of regional resource adequacy, Avista is hopeful the regional resource adequacy
program currently being designed is successfully implemented.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Chapter 8: Transmission & Distribution Planning

Avista Corp 2021 Electric IRP 8-1
8. Transmission & Distribution Planning

This chapter introduces the Avista Transmission and Distribution (T&D) systems and
provides a brief description of how Avista studies these systems and recommends capital
investments to keep the systems functioning reliably while accommodating future growth.
Avista’s Transmission System is only one part of the networked Western Interconnection
with specific regional planning requirements and regulations. This chapter summarizes
planned transmission projects and generation interconnection requests currently under
study and provides links to documents describing these studies in more detail. This
section also describes how distribution planning is incorporated in the IRP and Avista’s
merchant transmissions system rights.

Avista Transmission System
Avista owns and operates a system of over 2,200 miles of electric transmission facilities
including approximately 700 miles of 230 kV transmission lines and 1,570 miles of 115
kV transmission lines (see Figure 8.1).

Figure 8.1: Avista Transmission System

Section Highlights
 Avista actively participates in regional transmission planning forums.
 Avista develops annual transmission and distribution system plans.
 Transmission Planning estimates costs of locating new generation on the Avista
system for the IRP.
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Avista Corp 2021 Electric IRP 8-2
230 kV Transmission System
The backbone of the Avista Transmission System operates at 230 kV. Figure 8.2 shows
a station-level drawing of Avista’s 230 kV Transmission System including
interconnections to neighboring utilities. Avista’s 230 kV Transmission System is
interconnected to the BPA 500 kV transmission system at the Bell, Hot Springs and
Hatwai Stations.

Figure 8.2: Avista 230 kV Transmission System

Transmission Planning Requirements and Processes
Avista coordinates transmission planning activities with neighboring interconnected
transmission owners. Avista complies with FERC requirements related to both regional
and local area transmission planning. This section describes several of the processes
and forums important to Avista’s transmission planning.

Western Electricity Coordinating Council
The Western Electricity Coordinating Council (WECC) is the group responsible for
promoting bulk electric system reliability, compliance monitoring and enforcement in the
Western Interconnection. This group facilitates development of reliability standards and
helps coordinate interconnected system operation and planning among its membership.
WECC is the largest geographic territory of the regional entities with delegated authority
from the National Electric Reliability Council (NERC) and the Federal Energy Regulatory
Commission (FERC). It covers all or parts of 14 Western states, the provinces of Alberta
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Avista Corp 2021 Electric IRP 8-3
and British Columbia and the northern section of Baja, Mexico.1 See Figure 8.3 for the
map of NERC Interconnections including WECC.

RC West
California ISO’s RC West performs the federally mandated Reliability Coordinator
function for a portion of the Western Interconnection. While each transmission operator
within the Western Interconnection operates its respective transmission system, RC West
has the authority to direct specific actions to maintain reliable operation of the overall
transmission grid.

Figure 8.3: NERC Interconnection Map

Northwest Power Pool
Avista is a member of the Northwest Power Pool (NWPP), an organization formed in 1942
when the federal government directed utilities to coordinate river and hydro operations to
support wartime production. The NWPP serves as a northwest electricity reliability forum,
helping to coordinate present and future industry restructuring, promoting member
cooperation to achieve reliable system operation, coordinating power system planning
and assisting the transmission planning process. NWPP membership is voluntary and
includes the major generating utilities serving the Northwestern U.S., British Columbia
and Alberta. The NWPP operates several committees, including its Operating Committee,
the Reserve Sharing Group Committee, the Pacific Northwest Coordination Agreement
(PNCA) Coordinating Group and the Transmission Planning Committee (TPC).

NorthernGrid
NorthernGrid formed on January 1, 2020. Its membership includes thirteen utility
organizations within the northwest and many external stakeholders. NorthernGrid aims to
enhance and improve the operational efficiency, reliability and planned expansion of the
Pacific Northwest transmission grid. Consistent with FERC requirements issued in Orders

1 https://www.wecc.biz/Pages/About.aspx.
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890 and 1000, NorthernGrid provides an open and transparent process to develop sub-
regional transmission plans, assess transmission alternatives (including non-wires
alternatives) and provide a decision-making forum and cost-allocation methodology for
new transmission projects. NorthernGrid is a new regional planning organization created
by combining the members of ColumbiaGrid and the Northern Tier Transmission Group.

System Planning Assessment
Development of Avista’s annual System Planning Assessment (Planning Assessment)
encompasses the following processes:
 The Avista Local Transmission Planning Process – as provided in Attachment K,
Part III of Avista’s Open Access Transmission Tariff (OATT);
 The NorthernGrid transmission planning process – as provided in the
NorthernGrid Planning Agreement; and
 The requirements associated with the preparation of the annual Planning
Assessment of the Avista portion of the Bulk Electric System.
The Planning Assessment, or Local Planning Report, is prepared as part of a two-year
process as defined in Avista’s OATT Attachment K. The Planning Assessment identifies
the Transmission System facility additions required to reliably interconnect forecasted
generation resources, serve the forecasted loads of Avista’s Network Customers and
Native Load Customers, and meet all other Transmission Service and non-OATT
transmission service requirements, including rollover rights, over a 10-year planning
horizon. The Planning Assessment process is open to all interested stakeholders,
including, but not limited to Transmission Customers, Interconnection Customers and
state authorities.

Avista’s OATT is located on its Open Access Same-time Information System (OASIS) at
http://www.oatioasis.com/avat. Additional information regarding Avista’s System Planning
work is in the Transmission Planning folder on Avista’s OASIS. The Avista System
Planning Assessment is posted on OASIS. Avista’s most recent transmission planning
document highlights several areas for additional transmission expansion work including:

 Big Bend - Transmission system capacity and performance will significantly
improve upon completion of the Benton – Othello Switching Station 115 kV
Transmission Line rebuild project and the Saddle Mountain 230 kV Station project,
which adds a fourth source into the load area. The addition of communication aided
protection schemes and other reconductor projects will improve reliability and
lessen the impacts of system faults. This project is needed for continued
integration of utility scale renewable generation.

 Coeur d’Alene - The completion of the Coeur d’Alene – Pine Creek 115 kV
Transmission Line Rebuild project and Cabinet – Bronx – Sand Creek 115 kV
Transmission Line Rebuild project improved transmission system performance in
northern Idaho. The addition and expansion of distribution substations and a
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Avista Corp 2021 Electric IRP 8-5
reinforced 115 kV transmission system are needed in the near-term planning
horizon to support load growth and ensure reliable operations in this.

 Lewiston/Clarkston - Load growth in the Lewiston/Clarkson area contributed to
heavily loaded distribution facilities. Additional performance issues have been
identified related to the ability for bulk power transfer on the 230 kV transmission
system. A system reinforcement project is under development to accommodate
the load growth in this area.

 Palouse - Completion of the Moscow 230 kV Station rebuild project in 2014
mitigated several performance issues. The remaining issue is a potential outage
of both the Moscow and Shawnee 230/115 kV transformers. An operational and
strategic long-term plan is under development to best address a possible double
transformer outage in this area.

 Spokane - Several performance issues exist with the present state of the
transmission system in the Spokane area and are expected to worsen with
additional load growth. The Westside 230 kV station rebuild is near completion and
the rebuild at the Irvin 115 kV station is ongoing. The staged construction of new
230 kV facilities at the Garden Springs 230 kV station is under development.
Dependency on the 230 kV Beacon station leaves the system susceptible to
performance issues for outages related to transmission lines that terminate at the
station.

IRP Generation Interconnection Options (Table 8.1) shows the projects and cost
information for each of the IRP-related studies where Avista evaluated new generation
options. These studies provide a high-level view of generation interconnection costs and
are similar to third-party feasibility studies performed under Avista’s generator
interconnection process. In the case of third-party generation interconnections, FERC
policy requires a sharing of costs between the interconnecting transmission system and
the interconnecting generator. Accordingly, Avista anticipates all identified generation
integration transmission costs will not be directly attributable to a new interconnected
generator.

Large Generation Interconnection Requests
Third-party generation companies may request transmission studies to understand the
cost and timelines required for integrating potential new generation projects. These
requests follow a strict FERC process to estimate the feasibility, system impact and facility
requirement costs for project integration. After this process is completed, a contract offer
to integrate the project may occur and negotiations can begin to enter into a transmission
agreement if necessary. Table 8.2 lists information associated with potential third-party
resource additions currently in Avista’s interconnection queue.2

2 https://www.oasis.oati.com/woa/docs/AVAT/
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Table 8.1: 2021 IRP Generation Study Transmission Costs

Station Request (MW) POI Voltage Cost Estimate ($ million)3
Kootenai County (GF) 100 230 kV 4
Kootenai County (GF) 200/300 230 kV 80-100
Rathdrum 25/50/100 115 kV <1
Rathdrum 200 115 kV 55
Rathdrum 50/100 230 kV <1
Rathdrum 200 230 kV 60
Benewah 100/200 230 kV <1
Tokio 50/100 115 <1, 20
Othello/Lind 50/100/200 115 kV Queue Issues4
Lewiston/Clarkston 100/200 230 kV <1
Northeast 10 115 kV <1
Kettle Falls 12 115 kV <1
Kettle Falls 24/100/124 115 kV <20
Long Lake 68 115 kV 33
Monroe Street 80 115 kV 2
Post Falls 10 115 kV <1
Cabinet Gorge 110 230 kV <14

3 Cost estimates are in 2019 dollars and use engineering judgment with a 50 percent margin for error.
4 This area of the system has several projects in the transmission request process, in total these projects
exceed the local area’s ability to integrate new resources and the issue is currently being studied.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Avista Corp 2021 Electric IRP 8-7
Table 8.2: Third-Party Large Generation Interconnection Requests

Project Size Type Interconnection Proposed Date
#46 126 Wind Big Bend (WA) December 2018
#47 750 Wind Colstrip 500kV (MT) September 2018
#52 100 Solar Big Bend (WA) July 2020
#60 150 Solar & Storage Lewiston/Clarkston December 2022
#62 123 Wind Big Bend (WA) November 2021
#66 71 Wood Waste Kettle Falls (WA) July 2023
#67 80 Solar Big Bend (WA) June 2023
#69 750 Wind Colstrip 500kV (MT)
#70 2.5 Storage Liberty Lake (WA)
#72 80 Solar Big Bend (WA) June 2021
#76 200 Solar Big Bend (WA) December 2020
#81 94 Solar Big Bend (WA) June 2020
#84 5 Solar Kettle Falls (WA) August 2020
#94 5 Solar Big Bend (WA) August 2021
#97 100 Solar & Storage Lewiston/Clarkston December 2021
#101 500 Solar & Storage Lewiston/Clarkston September 2024
#105 5 Solar Big Bend (WA) June 2021
#108 750 Wind Colstrip 500kV (MT) October 2023

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Distribution Planning
Avista continually evaluates its distribution system for continued reliability and level of
service requirements for current and future loads. The distribution system consists of
approximately 350 feeders covering 30,000 square miles, ranging in length from three to
73 miles. For rural distribution, feeder lengths vary widely to meet electrical loads resulting
from the startup and shutdown of customers in the timber, mining and agriculture
industries. The distribution evaluation determines if there are capacity limitations on the
system to serve current and future projected load for each individual feeder. The analysis
also considers if the system meets reliability and level of service requirements including
voltage and power quality. When a potential constraint is identified, an action plan is
prepared and compared against other options, and the best course of action is budgeted
for implementation.

Electric distribution planning identifies system capacity and service reliability constraints,
and subsequently determines the best and lowest life-cycle cost solution for those
constraints. Solutions traditionally center on infrastructure upgrades such as poles, wire
and cable. New technologies are emerging and may impact system analysis, including
storage, photovoltaic (solar) and demand response. As these alternatives mature and
evolve, they are likely to play a growing role in Avista’s investment portfolio either as
primary solutions or as capital deferment solutions. Avista has deployed several
distribution level pilot projects to determine the best means to meet customer needs while
maintaining a high degree of reliability now and in the future.

Load and system data are required to properly evaluate each feeder for new technologies.
Quality load data is not available for all the Avista feeders beyond monthly data logs
recording peak load and energy usage. Avista has 200 of 347 feeders with three-phase
Supervisory Control and Data Acquisition (SCADA) data available. Avista adds SCADA
capability to more feeders as resources and budgeting within our substation work
schedule allows. Evaluating new technologies is limited to portions of the system with the
available data until new sources of data are developed and brought online. Detailed data
is required to validate whether new technologies solve current system constraints or just
defer the constraint for a period of time. Avista is installing automated meters for
customers in Washington and plans to install these meters in Idaho in the next few years.
When complete, the new meters will be able to collect additional data needed to improve
the distribution planning process.

New load forecasting techniques such as spatial load forecasting will be required for
distribution planning. This new forecasting method uses Geographic Information System
(GIS) based information associated with feeder location and can help forecast specific
feeder load growth by considering zoning, demographics, land availability and specific
parcel information. With additional investment in both technology and human capital,
Avista will be prepared to quickly study and implement new technologies on its distribution
system.

Deferred Capital Investment Analysis
New technologies such as storage, photovoltaics and demand response programs could
help the electrical system by deferring or eliminating future capital investments. This is
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dependent on new technologies to solve system constraints and meet customer
expectations for reliability. An advantage in using these technologies may be additional
benefits incorporated into the overall power system. For example, storage may help meet
overall power supply peak load needs, but it may also provide voltage support and defer
capital investment on the distribution feeder or at the distribution substation in the right
conditions (discussed below).

This section discusses the analysis for determining the capital investment deferment
value for distributed energy resources (DERs). Capital investment deferment is not the
same for all locations on the system. Feeders differ by whether they are summer or winter
peaking, the time of day when the peaks occur, whether they are at or near capacity, and
the speed of local load growth. It is not practical to have an estimate for each feeder in
an IRP, but it is prudent to have a representative estimate included in the IRP resource
selection analysis.

In order to fairly evaluate and select the most cost-effective solutions for system
deficiencies, the planning process needs to identify the deficiency well in advance of
becoming a problem. Longer evaluation periods provide for a more comprehensive
evaluation so the solution can take a holistic approach to include system resource needs.
A shorter period requires immediate action and does not lend itself to a stacked value
analysis due to time constraints for acquiring and constructing a non-wire alternative.

Identifying future deficiencies in a timely matter has become the focus of System
Planning. As previously mentioned, spatial forecasting, load data, time series analysis
and accurate modeling are critical to making decisions as early as possible. Although
DER opportunities will continue to be evaluated, System Planning needs the tools,
process and time to evaluate whether DERs are the preferred solution in any given
situation.

At this time, Distribution Planning has not identified any projects meeting the criteria for
an economic non-wire alternative. The near-term distribution projects require capacity
increases and duration requirements due to load growth exceeding the distributed energy
resources (DERs) capability. Avista is starting a public distribution planning process in
2022 to identify and plan for future distribution needs.

Reliability Impact of Distributed Energy Storage
Utility-scale batteries may offer benefits to grid operations. Reliability is one benefit often
associated with batteries. This is particularly true in situations where the battery system
is commissioned as a mitigation solution on the distribution system.

There is an industry trend to broaden the list of remedies available to alleviate grid
deficiencies beyond traditional wires-based solutions. The solutions are typically called
“non-wire” alternatives but it may be more informative to call them non-traditional
alternatives. The motivation behind the trend is reasonable as non-traditional approaches
may be less expensive than legacy options and may also incorporate other ancillary
benefits, such as in the case of batteries. Utilities should consider all viable options to
arrive at a least cost and reliable solution to distribution issues. In addition to solving grid
issues, some non-wire alternatives may also serve as a system resource. Typically, these
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are referred to as a Distributed Energy Resource. Batteries, the subject of this section,
are one such non-wire alternative with other benefits.

It is often presumed batteries increase system reliability. This may be true in some
applications, but in the narrow sense of non-wire alternatives, this would not typically be
the case. In the simplest of terms, reliability can decrease with the addition of a battery
because the battery and its control system are additional failure points in the existing
system chain. It is difficult to identify a case where this reduction in reliability from the
added potential failure points is not true.

To demonstrate this point, a typical battery use case is presented as a thought
experiment. A common issue on the distribution grid is feeder capacity constraints. A
constrained feeder typically approaches the operational constraint during the daily peak
load. The historical mitigation for this type of constraint is to increase the capacity of the
constraining element by installing a larger conductor, different regulators, a larger
transformer, or building a new substation. With the advent of utility-scale batteries, utilities
have another option to mitigate these types of feeder constraints. Employing battery
storage to, in effect, shift load from the daytime when limited and expensive resources
are the norm, to the nighttime when relatively more abundant and less expensive
resources are readily available.

When used to fix a constraint in this manner the battery (or generating resource such as
a DER) is added to existing distribution facilities. It does not replace existing facilities, and
this is a key point. The probability of failure of the existing facilities remains. The
probability of failure of the battery or other non-wire alternative system is now an
additional failure point. Think of a feeder as a chain where each link is a potential failure
point. If the chain consists of 100 links, there are 100 points of possible failure along the
entire chain. In the same manner, adding a battery to a feeder to mitigate an issue simply
adds another link, and another possible failure point, in the chain. Instead of 100 possible
points of failure, there are now 101 possible points of failure. Granted, there are temporal
aspects to this as well. The battery will not always be needed to fix a constraint that does
not occur at all times. If a failure occurs in the battery when there is no constraint, the
feeder can continue operating as normal with no adverse impacts to the system. But there
will be times when the battery is needed to meet that peak event and during those times
the battery becomes an additional failure point with the expanded system. The annual net
effect on the feeder is reduced reliability.

The shift in reliability is more significant if a traditional solution was chosen. Existing, older
links in the failure chain would be replaced with new and often more robust and more
reliable links. To take the chain analogy even further, if a new substation is built, links are
removed from the failure chain as each affected feeder becomes shorter and has less
environmental exposure. In addition, there is increased resiliency due to added
operational flexibility and the ability to serve load from different directions. The net effect
of a traditional solution is increased reliability and it facilitates future DER resource
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Avista Corp 2021 Electric IRP 8-11
additions because traditional solutions make the grid better able to accept the additional
DERs.

Quantifying the real effect of a grid-fixing battery, or similar resource, on reliability is
difficult and situational. Indeed, it may not rise to a level of concern given the temporal
nature of the decrease in reliability. The benefit of the resource may outweigh the short
period of time it increases failure probability. However, if it increases failure probability for
a significant period an alternate solution may be warranted. From an IRP perspective, the
notion that fixing a distribution grid deficiency while simultaneously providing a system
resource is an intriguing one. It is worthy of consideration, but one can’t assume system
reliability will not be negatively impacted by doing so.

Merchant Transmission Rights
Avista has two types of transmission rights. The first rights include Avista’s owned
transmission. This transmission is reserved and purchased by Avista’s merchant
department to serve Avista customers. Avista owned transmission is also available to
other utilities or power producers. FERC separates utility functions between merchant
and transmission functions to ensure fair access to the Avista transmission system. The
merchant department dispatches and controls the power generation for Avista and
purchases transmission from the Avista transmission operator to ensure energy can be
delivered to customers. Avista must show a load serving need to reserve transmission on
the Avista owned transmission system to ensure equitable access to the transmission
capacity. Appendix H shows the projected need and future use of the Avista transmission
system.

Avista also purchases transmission rights from other utilities to serve customers. This
transmission is procured on behalf of the merchant side of Avista. The merchant group
has transmission rights with BPA, PGE and a few smaller local electric utilities. Table 8.4
shows the third-party transmission rights contracted by Avista’s merchant group.

Table 8.3: Merchant Transmission Rights

Counterparty Path Quantity (MW)Expiration
BPA Lancaster to John Day 100 6/30/2026
BPA Coyote Springs 2 to Hatwai 97 8/1/2026
BPA Garrison to Hatwai 196 8/1/2026
BPA Coyote Springs 2 to Vantage 125 10/31/2022
PGE John Day to COB 100 12/31/2023
Northern Lights Dover to Sagle As needed n/a

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Avista Corp 2021 Electric IRP 9-1
9. Supply-Side Resource Options

Avista evaluates several different generation, storage and hybrid solar/storage supply-
side resource options to meet future resource deficits. The resource categories evaluated
for this IRP included upgrading existing resources, building and owning new generation
facilities and contracting with other energy companies. This section describes the costs
and characteristics of resource options Avista considered in the 2021 IRP. The options
are mostly generic, as actual resources are typically acquired through competitive
processes such as an RFP. This process may yield resources that differ in size, cost and
operating characteristics due to siting, engineering or financial requirements, it also may
reveal existing resource options.

Assumptions
Avista models only commercially available resources with well-known costs and
generation profiles priced as if Avista developed and owned the generation or acquired
generation from Independent Power Producers (IPPs) through a Purchase Power
Agreement (PPA). Resources using PPAs rather than ownership include pumped hydro
storage, wind, solar (with and without storage), geothermal and nuclear resources. Avista
modeled these resource types as PPAs since IPPs financially capture tax benefits for
these resources earlier, reducing the cost to customers. Resource options assuming
utility ownership include natural gas-fired combined cycle combustion turbines (CCCT),
simple cycle combustion turbines (SCCT), natural gas-fired reciprocating engines,
hydrogen-fired SCCT, energy storage, hydrogen fuel cell, biomass, hydroelectric
upgrades, hydroelectric contracts and thermal unit upgrades. Upgrades to coal-fired units
were not included or considered in this IRP. Modeling resources as PPAs or ownership
does not preclude the utility from acquiring new resources in other manners but serves
as an appropriate cost estimate for the new resources. Several other resource options
described later in the chapter are not included in the portfolio analysis but are discussed
here as potential resource options since they may appear in a future request for resource
acquisition.
Section Highlights
 Solar, wind and other renewable resource options are modeled as Purchase
Power Agreements (PPA) instead of utility ownership.
 Upgrades to Avista’s hydro, natural gas and biomass facilities are included as
resource options.
 Future competitive acquisition processes might identify different technologies
available to Avista at a different cost, size or operating characteristics and may
include existing generation options.
 Renewable resource costs assume no extensions of current state and federal
tax incentives.
 Avista models several energy storage options including pumped storage hydro,
lithium-ion, vanadium flow, zinc bromide flow, liquid air and hydrogen.
 In addition to industry sources, Avista’s recent Renewable RFP informed IRP
inputs on solar, wind and hybrid solar/storage resource options.
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It is difficult to accurately model potential contractual arrangements with other energy
companies as an option in the plan specifically for existing units or system power, but
such arrangements may offer a lower customer cost when a competitive acquisition
process is completed. Avista plans to use competitive RFP processes for resource
acquisitions where possible to ensure the lowest cost resource is acquired for customers.
However, another acquisition process may yield better pricing on a case-by-case basis,
especially for existing resources available for shorter time periods. When evaluating
upgrades to existing facilities, Avista uses the IRP, RFPs and market intelligence to
determine and validate its upgrade assumptions. Upgrades typically require competitive
bidding processes to secure contractors and equipment.

The costs of each resource option within this chapter do not include the cost related to
upgrading the transmission or distribution system described in Chapter 8 – Transmission
& Distribution Planning or third-party wheeling costs. All costs are considered at the bus
bar. Avista excludes these costs in this chapter to allow for cost comparison as resource
costs at specific locations are highly dependent on the location chosen in relation to
Avista’s system. These costs are included when Avista evaluates the resources for
selection in an RFP and within the IRP’s portfolio analysis. All costs are levelized by
discounting nominal cash flows by the 6.70 percent-weighted average cost of capital
approved by the Idaho and Washington Commissions in recent rate case filings. All costs
in this section are in 2020 nominal dollars unless otherwise noted. All cost and operating
characteristic assumptions for generic resources and how PPA pricing were calculated
are available in Appendix I.

Avista relies on several sources including the NPCC, press releases, regulatory filings,
internal analysis, publicly available studies, developer estimates and Avista’s experience
with certain technologies to develop its generic IRP resource assumptions. In addition to
the above, Avista’s 2020 Renewable RFP was utilized to ensure assumed IRP costs for
solar, wind and solar/storage resource options were in line with pricing available from
actual projects.

Levelized resource costs illustrate the differences between generator types. The values
show the cost of energy if the plants generate electricity during all available hours of the
year. In actual operation, plants do not operate to their maximum generating potential
because of market and system conditions. Costs are separated between energy in
$/MWh and capacity in $/kW-year to better compare technologies1. Without this
separation of costs, resources operating infrequently during peak-load periods would
appear more expensive than baseload CCCTs, even though peaking resources are lower
total cost when operating only a few hours each year. Avista levelizes the cost using the
production capability of the resource. For example, a natural gas-fired turbine is available
92 to 95 percent of the time when accounting for maintenance and forced outage rates.
Avista divides the cost by the amount of megawatt hours the machine can produce. For
resources that are available but may not have the fuel available, such as a wind project,
the resource costs are divided by its expected production.

1 Storage technologies use a $ per kWh rather than $ per kW because the resource is both energy and
capacity limited.
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Tables at the end of this section show incremental capacity, heat rates, generation capital
costs, fixed O&M, variable costs and peak credits for each resource option.2 Table 9.1
compares the levelized costs of different resource types over a 30-year asset life.

Distributed Energy Resources (DERS)
This IRP includes several distributed energy resource options. DERs are both supply and
demand side resources located at either the customer location or at a utility-controlled
location on the distribution system. For demand side DERs other than energy efficiency,
the resource assumptions are typically demand response. Avista included these program
options in Chapter 6. Specific programs with physical DER assets include EV charging
and customer-owned battery and thermal storage along with many other options to lessen
customer load during peak events. In addition to these modeled demand-side DER
options, Avista included forecasts for customer-owned solar and EVs as part of its load
forecast discussed in Chapter 3.

In addition to demand-side DERs, supply-side resource options include small scale solar
and battery storage. Avista includes specific cost estimates for smaller scale projects
described later in this chapter along with the energy, capacity and ancillary services
benefits traditional utility scale projects offer. Due to the location, additional benefits such
as line loss savings over alternative utility scale projects are also included. Other
locational benefits may also be credited to the project if it alleviates distribution
constraints. Projects on the customer system may also provide reliability benefits to the
specific customer. At this time, Avista has not determined any specific locational value or
reliability benefits for these resources, but additional information can be found regarding
effects of DERs under distribution planning in Chapter 8. Avista also plans to include non-
energy impacts of DERs and utility scale resources in the next IRP.

Natural Gas-Fired Combined Cycle Combustion Turbine
Natural gas-fired CCCT plants provide reliable capacity and energy for a relatively modest
capital investment. The main disadvantages of a CCCT are generation cost volatility due
to reliance on natural gas, unless utilizing hedged fuel prices, and the plant emissions.
This IRP models CCCTs as “one-on-one” (1x1) configurations, using hybrid air/water
cooling technology and zero liquid discharge. The 1x1 configuration consists of a single
gas turbine with a heat recovery steam generator (HRSG) and a duct burner to gain more
generation from the steam turbine. The plants have nameplate ratings between 311 MW
and 586 MW each depending on configuration and location. A three-on-two (3x2) CCCT
plant configuration is possible with three turbines and two HRSG, generating up to 249
MW.

Cooling technology is a major cost driver for CCCTs. Depending on water availability,
lower-cost wet cooling technology could be an option, similar to Avista’s Coyote Springs
2 plant. However, absent water rights, a more capital-intensive and less efficient air-
cooled technology may be used. For this IRP, Avista assumes water is available for plant
cooling based on its internal analysis, but only enough water rights for a hybrid system
utilizing the benefits of combined evaporative and convective technologies.

2 Peak credit is the amount of capacity a resource contributes at the time of system one-hour peak load.
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This IRP models three types of CCCT plants, ranging in size from 235 MW to 480 MW as
1x1 configuration. Avista reviewed many CCCT technologies and sizes and selected
these plants due to the range in size to have the potential for the best fit for the needs of
Avista’s customers. If Avista pursues a CCCT, a competitive acquisition process will allow
analysis of other CCCT technologies and sizes at both Avista’s preferred and other
locations. It is also possible Avista could acquire an existing CCCT resource from one of
the many units in the Pacific Northwest.

The most likely location for a new CCCT is in Idaho, mainly due to Idaho’s lack of an
excise tax on natural gas consumed for power generation, a lower sales tax rate relative
to Washington and no state taxes or fees on the emission of carbon dioxide.3 CCCT sites
likely would be on or near our transmission system to avoid third-party wheeling costs.
Another advantage of siting a CCCT resource in Avista’s Idaho service territory is access
to relatively low-cost natural gas on the GTN pipeline. Avista already secured a site with
these potential connection points in the event it needs to add additional capacity from
either a CCCT or other technology.

Combined cycle technology efficiency has improved since Avista’s current CCCT
generating fleet entered service with heat rates as low as 6,400 Btu/kWh for a larger
facility and 6,700 for smaller configurations. Duct burners can add additional capacity with
heat rates in the 7,200 to 8,400 Btu/kWh range.

The anticipated capital costs for the modeled CCCTs, located in Idaho on Avista’s
transmission system with AFUDC on a greenfield site, range between $813 to $1,453 per
kW in 2020 dollars. A likely configuration of the modern technology is $1,048 per kW.
These estimates exclude the cost of transmission and interconnection. Table 9.1 shows
levelized plant cost assumptions split between capacity and energy for both the combined
cycle options discussed here, and the natural gas peaking resources discussed in the
next section. The costs include firm natural gas transportation, fixed and variable O&M
and transmission. Table 9.2 summarizes key cost and operating components of natural
gas-fired resource options. With competition from alternative technologies and the need
for additional flexibility for intermittent resources, it is likely to put downward pressure on
future CCCT costs.

Natural Gas-Fired Peakers
Natural gas-fired SCCTs and reciprocating engines, or peaking resources, provide low-
cost capacity capable of providing energy as needed. Technological advances coupled
with a simpler design relative to CCCTs allow them to start and ramp quickly, providing
regulation services and reserves for load following and variable resources integration.

This IRP modeled frame, hybrid-intercooled, reciprocating engines and aero-derivative
technologies. Peakers have different load following abilities, costs, generating capabilities
and energy-conversion efficiencies. Table 9.2 shows cost and operational characteristics

3 Washington state applies an excise tax on all fuel consumed for wholesale power generation, the same
as it does for retail natural gas service, at approximately 3.875 percent. Washington also has higher sales
taxes and carbon dioxide mitigation fees for new plants.
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based on internal engineering estimates. Peaking plants assume 0.1-0.5 percent annual
real dollar cost decreases and forced outage and maintenance rates. The levelized cost
for each of the technologies is in Table 9.1.

Firm natural gas fuel transportation is an electric generation reliability issue with FERC
and is also the subject of regional and extra-regional forums. For this IRP, Avista
continues to assume it will not procure firm natural gas transportation for peaking
resources and will use its current supply or short-term transportation for peaking needs.
Firm transportation could be necessary where pipeline capacity becomes scarce during
utility peak hours. Where non-firm transportation options become inadequate for system
reliability, four options exist: contracting for firm natural gas transportation rights,
purchasing an option to exercise the rights of another firm natural gas transportation
customer during times of peak demand, on-site fuel oil or nearby storage such as liquefied
natural gas.

Table 9.1: Natural Gas-Fired Plant Levelized Costs

Plant Name Total
$/MWh
$/kW-Yr
(Capability)
Variable
$/MWh
Winter
Capacity
(MW)
Advanced Small Frame CT 60 132 44 96
Frame/Aero Hybrid CT 52 138 36 93
Large Reciprocating Engine Facility 52 142 35 184
Small Reciprocating Engine Facility 57 170 36 91
Modern Small Frame CT 58 147 40 56
Aero CT 60 171 39 49
1x1 Large CCCT 41 114 27 615
1x1 Modern CCCT 48 161 28 329
3x2 Small CCCT 57 219 30 267

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Table 9.2: Natural Gas-Fired Plant Cost and Operational Characteristics4

Item Capital
Cost with
AFUDC
($2020/kW)
Fixed
O&M
($2020
/ kW-
Heat
Rate
(Btu/
kWh)
Variable
O&M
($/MWh)
Total
Project
Size
(MW)
Total
Cost
(Mil$-
2020)
Advanced Small Frame CT 1,040 4.80 11,352 4.00 84 87
Frame/Aero Hybrid CT 1,097 4.40 8,956 4.00 92 101
Large Recip. Engine Facility 1,145 4.30 8,382 5.00 184 211
Small Recip. Engine Facility 1,333 8.80 8,146 7.00 91 122
Modern Small Frame CT 1,137 7.90 9,817 5.00 51 58
Aero CT 1,319 9.10 9,512 5.00 44 58
1x1 Modern CCCT 1,048 13.60 6,765 4.00 311 326
1x1 Large CCCT 813 25.70 6,411 3.50 587 477
3x2 Small CCCT 1,453 32.10 6,779 5.00 249 362

Wind Generation
While wind resources benefit from having no direct emissions or fuel costs, they are not
typically dispatchable to meet load. Avista modeled four general wind location options in
this plan: Montana, Eastern Washington, the Columbia River Basin and offshore.
Configurations of wind facilities are changing given transmission limitations in the region,
benefits of tax credits, low construction prices and the potential for storage. These factors
allow for sites being built with higher capacity levels than the transmission system can
currently integrate. When the wind facilities generate additional MWh above the physical
transmission limitations5, the generators typically feather or store energy using onsite
energy storage. At this time, Avista is not modeling wind with onsite storage or wind
facilities with greater output capabilities then can be integrated on the transmission
system. Since storage at a wind facility does not benefit from tax incentives, Avista’s
modeling process allows for storage to be sited at a wind facility if cost effective.

Onshore wind capital costs in 2020, including construction financing, are $1,300 per kW
for Washington on-system projects, off-system projects including locations in Oregon and
Montana are $1,268 per kW, and offshore wind is $2,950 per kW. The annual fixed O&M
costs of $32.30 per kW-year is for onshore wind and $95.00 per kW-year for offshore
wind. Fixed O&M does not include indirect charges to account for the inherent variation
in wind generation often referred to as wind integration. The cost of wind integration
depends on the penetration of wind resources in Avista’s balancing authority and the
market price of power.

Wind capacity factors in the Northwest range between 25 and 40 percent depending on
location and in the 45 to 55 percent range in Montana and offshore locations. This plan
assumes Northwest wind has a 35 percent average capacity factor. A statistical method,
based on regional wind studies, derives a range of annual capacity factors depending on

4 Costs based on Idaho. Washington’s costs would be slightly higher due to higher sales tax rate of 8.9%
compared with Idaho’s 6.0% rate.
5 If transmission is limited due to contractual reasons, an additional option is to buy non-firm transmission
to move the power.
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the wind regime in each year (see stochastic modeling assumptions section for details in
Chapter 10).

This IRP estimated potential costs for offshore wind. Offshore wind has the potential for
higher capacity factors (55 percent), but development and operating costs are higher. At
the time of this IRP, developers have not been offering an offshore product in the Pacific
Northwest. The pricing and costs are estimates based on other proposals in North
America and were not directly modeled in this IRP as a resource option.

As discussed above, levelized wind costs change substantially due to the capacity factor
but can change even more from tax incentives and the ownership structure of the facility.
Table 9.3 shows the nominal levelized prices with different start dates for each modeled
location. These price estimates assume the facility is acquired using a 20-year PPA with
a flat pricing structure, the intermittent generation integration charge for the first 100 MW
added to Avista’s system, and includes costs associated with the cost of the PPA, excise
taxes, commission fees, and uncollectables to customers. These costs do not include the
transmission costs for either capital investment or wheeling purchases. If a PPA is
selected in Avista’s preferred resource strategy (Chapter 11), the model assumes the
PPA will extend through the 24-year time period.

Photovoltaic Solar
Photovoltaic (PV) solar generation technology costs have fallen substantially due to low-
cost imports and from increased demand driven by renewable portfolio standards. Solar
systems are often built with more generating capacity than the transmission interconnect
allows to take advantage of those limited times when full energy production can be
utilized. To help with integration of intermittent production, some systems have storage
connected to the system to avoid curtailment by storing excess energy or shifting energy
to higher priced hours. Solar plus storage has an advantage, compared to other
renewable systems, because storage may qualify for investment tax credits when paired
with solar if the stored energy is generated by solar. Since both systems use DC power,
they can utilize the same power inverters. Other renewable resources may not benefit
from this tax provision because production, rather than capital spending, drive the tax
credits for those resources. It is possible future solar incentives will be similar to the
Production Tax Credit rather than the Investment Tax Credit (ITC).

Avista models three solar systems for this IRP. The first is an on-system solar facility in
25 MW (AC) increments, modeled as a facility with at least 100 MW to take advantages
of economies of scale. Solar costs can change significantly depending on the size of the
project; to address this issue, a smaller 5 MW (AC) on-system solar option is also
included. The third solar option includes a 100 MW facility to be wheeled to Avista from
higher solar production areas such as southern Idaho or Oregon. While any location can
participate in a future RFP, transmission charges and availability will determine if a project
moves forward with Avista.

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Table 9.3: Levelized Wind Prices ($/MWh)

Year On-System
Wind
Off-System
Wind
Montana
Wind
OffShore
Wind
2022 37 36 25 68
2023 44 41 31 72
2024 55 53 42 82
2025 56 53 42 81
2026 56 54 43 80
2027 57 55 43 79
2028 57 55 44 78
2029 58 56 44 77
2030 58 56 44 77
2031 59 57 45 77
2032 59 57 45 77
2033 60 58 46 77
2034 61 59 47 78
2035 62 60 47 78
2036 63 61 48 78
2037 63 62 49 79
2038 64 63 50 79
2039 65 64 50 79
2038 66 64 51 79
2039 67 66 52 79
2040 68 67 53 80
2041 69 68 54 81
2042 70 69 54 81
2043 71 70 55 82
2044 37 36 25 83
2045 44 41 31 83

Solar capital costs have been rapidly declining despite increasing tariffs costs.
Technological improvements such as bi-facial panels make solar more efficient at
delivering energy per square meter. For this IRP, larger systems assume a cost of $1,000
per kW (AC) for a single axis tracking system; by 2030, these costs are expected to rise
to $1,219 per kW and $1,486 per kW by 2040 from inflation. While these costs increase
in nominal dollars, real solar costs are likely to fall. Smaller systems assume premium
prices due to a lack of economies of scale with a price of $2,347 per kW in 2030 with
similar price changes as larger systems in the future. The cost to operate solar depends
on the size of the facility and location due to property taxes and lease payments; given
these varying costs, Avista assumes $11 per kW-year for larger systems and $14 per kW-
year for smaller systems.

Table 9.4 shows the levelized prices for 20-year flat PPAs with additional costs to
integrate the first 100 MW of intermittent generation, excise taxes, commission fees and
uncollectables. These costs do not include transmission costs associated with either new
construction or wheeling purchases.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 157 of 317
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Avista Corp 2021 Electric IRP 9-9
Table 9.4: Levelized Solar Prices

Year On-system Southern On-system
2022 32 29 63
2023 32 28 62
2024 40 36 80
2025 40 35 79
2026 38 34 76
2027 37 34 74
2028 37 33 73
2029 36 33 72
2030 36 32 71
2031 36 33 71
2032 36 33 71
2033 36 33 72
2034 37 33 72
2035 37 33 72
2036 37 33 72
2037 37 33 72
2038 37 33 72
2039 37 33 72
2040 37 33 73
2041 38 34 73
2042 38 34 73
2043 38 34 74
2044 38 34 74
2045 39 34 74

Solar Energy Storage (Lithium-Ion Technology)
As previously discussed, storage paired with solar takes advantage of federal tax credits,
lowers transmission costs, shifts energy deliveries, manages intermittent generation,
uses common equipment, increases peak reliability and can prevent energy oversupply.
Avista must study each potential benefit to see its value and the amount of storage
duration that is cost effective for each potential project. While the solar plus storage
system receives tax incentives (approximately six years) it must be only supplied with
solar energy. This limits the value of the storage asset due to its inability to assist with
larger system variations.

Lithium-ion technology prices are declining and will likely continue to fall. Avista estimates
the additional cost for more hours of storage in Table 9.5 for solar PPAs6. Avista modeled
two two-hour duration and one four-hour duration options; although, 15 to 30 minutes
would be considered if the technology is limited to assist with integrating intermittent
generation rather than reliability. Avista’s experience with solar generation from its 19.2
MW Adams Neilson PPA shows significant energy variation due to cloud cover. For this
IRP, Avista considers the benefits for reducing the variable generation integration costs

6 This table includes the values used in the IRP’s PRiSM model, due to the complexity of these
arrangements the costs within Appendix I may differ than those shown here due to modeling changes.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Avista Corp 2021 Electric IRP 9-10
and enhanced resource adequacy of the storage device. Currently, due to the complexity
and range of potential storage configurations, the IRP limits the storage options to a four-
hour and two-hour designs. In addition, Avista’s modeling of solar plus storage allows the
storage device to use grid power as it may when tax incentives end after six years.

Table 9.5: Storage Cost w Solar System ($/kW-month)

Year 100 MW/ 100 MW/
2022 8.2 7.3
2023 8.1 7.4
2024 6.2 5.7
2025 6.2 5.8
2026 6.4 6.2
2027 6.3 6.3
2028 6.2 6.4
2029 6.2 6.5
2030 6.1 6.7
2031 6.1 6.7
2032 6.1 6.8
2033 6.1 6.9
2034 6.1 7.0
2035 6.1 7.1
2036 6.1 7.2
2037 6.1 7.3
2038 6.2 7.4
2039 6.2 7.5
2040 6.2 7.6
2041 6.2 7.7
2042 6.3 7.9
2043 6.3 8.0
2044 6.3 8.1
2045 6.4 8.2

Stand-Alone Energy Storage
Energy storage resources are gaining significant traction as a resource of choice in the
western U.S. While energy storage does not create energy, it shifts it from one period to
another in exchange for a portion of the energy stored. Avista modeled several energy
storage options including pumped hydro storage, lithium-ion, vanadium flow, zinc bromide
flow, liquid air and hydrogen. In addition to the technology differences, Avista also
considers different energy storage durations for each technology. Pricing for energy
storage is also rapidly changing due to the technology advancements currently taking
place. In addition to changing prices for existing technologies, new technologies are
entering the storage space. The rapid change in pricing and new available technologies
justifies the need for frequent updates to the IRP analysis.

Another challenge with storage concerns pumped hydro technology where costs and
storage duration can be substantially different depending on the geography of the
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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proposed project. Storage is also gaining attention to address transmission and
distribution expansion, where the technology can alleviate conductor overloading and
short duration load demands rather than adding physical line/transformation capacity.

The storage costs discussed in this chapter are shown as the levelized cost for the
duration capability of the storage resources. This means the cost of capital and operations
are levelized then divided by the duration in kilowatt-hours of the resource. Storage
cannot be shown in $ per MWh as with other generation resources because they do not
create energy, only store it with losses. This analysis shows the cost differences between
the technologies but does not consider the efficiency of the storage process or the cost
of the energy stored. This analysis is performed in the resource selection process. Figure
9.1 summarizes the storage technologies based on upfront capital cost and duration using
costs in 2030 dollars

Figure 9.1: Storage Upfront Capital Cost versus Duration

Pumped Hydro Storage
The most prolific energy storage technology currently used in both the U.S. and the world
is pumped hydro storage. This technology requires the use of two or more water
reservoirs with different elevations. When prices or load are low, water is pumped to a
higher reservoir and released during higher price or load periods. This technology may
help with meeting system integration issues from intermittent generation resources.
Currently only one of these projects exists in the northwest and several more are in
various stages of the permitting process. An advantage with pumped hydro is the
technology has a long service life and is a technology Avista is familiar with as a hydro
generating utility. The greatest disadvantages are large capital costs and long-permitting
cycles.

Dist Scale Lithium-ion
Dist Scale Lithium-ionLithium-ion
Lithium-ion
Lithium-ion
Vanadium Flow Battery
Zinc Bromide Flow Battery
Hydrogen Fuel Cell
Hydrogen Gas Tubine
Liquid Air
Pumped Hydro Generic Option 1
Pumped Hydro Generic Option 2
Pumped Hydro (PPA Option 3)
Pumped Hydro (PPA Option 4)
Pumped Hydro (PPA Option 5)
Pumped Hydro (PPA Option 6)
-
50
100
150
200
250
300
350
400
0 10 20 30 40 50 60 70 80
$2
0
3
0

C
a
p
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o
s
t
Duration Hours
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 160 of 317
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Avista Corp 2021 Electric IRP 9-12
The technology has good round trip efficiency rates (Avista assumes 81 percent for most
options). When projects are developed, they are designed to utilize the amount of water
storage in each reservoir and the generating/pump turbines are sized for how long the
capacity needs to operate. For the IRP resource analysis, Avista models the technology
with six different durations: 8.5, 10, 12, 16, 24 and 70 hours. These durations indicate the
number of hours the project can run at full capacity. The pricing and durations of these
facilities are based on projects currently being developed in the northwest. Modeling
different duration times are required since in an energy-limited system, Avista requires
resources with enough energy to provide reliable power over an extended period in
addition to meeting single hour peaks. This study used the ELCC analysis discussed later
in the chapter to determine the Peak Credit for pumped hydro storage. Avista bases its
pricing for pumped hydro using a PPA financing methodology with fixed and variable
payments for four of the modeled options (3 through 6) to replicate current pumped hydro
opportunities in the northwest. Avista also modeled two potential ownership projects in
the event of future developments (options 1 and 2). The complete range in levelized cost
for pumped hydro is shown in Table 9.6. PPA options also include a $5 per MWh
(escalating with inflation) variable payment for each MWh generated.

Table 9.6: Pumped Hydro Company-Owned Options

Year Option 1
(16 hr)
Option 2
(24 hr)
Option 3
(70 hr)
Option 4
(8.5 hr)
Option 5
(12 hr)
Option 6
(10 hr)
$/kW-$/kW-$/kW-$/kW-$/kW-$/kW-
2022 420.2 437.8 21.76 23.28 15.19 25.15
2023 426.6 444.4 22.07 23.62 15.42 25.53
2024 433.0 451.1 22.39 23.98 15.64 25.91
2025 439.6 457.9 22.72 24.34 15.88 26.30
2026 446.2 464.8 23.05 24.70 16.11 26.69
2027 453.0 471.9 23.39 25.07 16.35 27.09
2028 459.8 479.0 23.73 25.45 16.60 27.50
2029 466.8 486.3 24.07 25.83 16.84 27.91
2030 473.9 493.6 24.42 26.22 17.09 28.32
2031 481.0 501.1 24.78 26.61 17.35 28.75
2032 488.3 508.7 25.13 27.01 17.61 29.18
2033 495.7 516.4 25.50 27.42 17.87 29.61
2034 503.2 524.2 25.87 27.83 18.14 30.06
2035 510.8 532.1 26.25 28.24 18.41 30.50
2036 518.6 540.2 26.63 28.67 18.68 30.96
2037 526.4 548.4 27.01 29.10 18.96 31.42
2038 534.4 556.7 27.41 29.53 19.24 31.89
2039 542.5 565.1 27.80 29.98 19.53 32.37
2040 550.7 573.6 28.21 30.43 19.82 32.85
2041 559.1 582.3 28.62 30.88 20.11 33.34
2042 567.5 591.1 29.03 31.35 20.41 33.84
2043 576.1 600.1 29.45 31.82 20.71 34.35
2044 584.9 609.2 29.88 32.29 21.02 34.86
2045 593.7 618.4 30.31 32.78 21.34 35.38
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 161 of 317
Chapter 9: Supply-Side Resource Options
Avista Corp 2021 Electric IRP 9-13
Lithium-Ion
Lithium-ion technology is one of the fastest growing segments of the energy storage
space. When coupled with solar, both tax advantages and economies of scope can
reduce the upfront pricing. This discussion focuses on using energy storage as a stand-
alone resource rather than coupled with solar. Stand-alone lithium-ion assumes a utility
owned asset for modeling purposes, but it could be acquired through a PPA as well with
two 10-year cycles for a 20-year life. Fixed O&M costs include replacement cells to
maintain the energy conversion efficiency and capacity for this storage option.

The lithium-ion technology is an advanced battery using ionized lithium atoms in the
anode to separate their electrons. This technology can carry high voltages in small spaces
making it a preferred technology for mobile devices, power tools and electric vehicles.
The large manufacturing sector of the technology is driving prices lower permitting the
construction of utility scale projects.

Avista modeled five conceptual stand-alone configurations for lithium-ion batteries. Two
DER small-scale sizes (5 MW) with four- and eight-hour durations for modeling the
potential for use on the distribution system and three larger systems (25 MW) including
four- and eight-hour durations as well as a theoretical 16-hour configuration were derived
from publicly available energy consultant sources. Figure 9.1 show the forecast for each
of the sizes and durations considered. Avista classifies the 4-hour battery as the standard
technology with a capital cost of $1,288 per kW in 2020 dollars. Fixed O&M costs are also
expected to decline; Avista assumed for the 4-hour technology an annual cost of $238.60
per kW-year in 2022 and falling to $222.50 per kW-year by 2032.

Figure 9.2: Lithium-ion Capital Cost Forecast

$0
$100
$200
$300
$400
$500
$600
$700
$800
$900
20
2
2
20
2
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20
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$
p
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k
W
Distribution Scale 4hr Distribution Scale 8hr Utility Scale 4 hr
Utility Scale 8 hr Utility Scale 16 hr
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Chapter 9: Supply-Side Resource Options
Avista Corp 2021 Electric IRP 9-14
Storage technology is often displayed in many methods to illustrate the cost because it is
not a traditional capacity resource. Table 9.7 shows levelized cost per kW for each
configuration. This calculation factor levelizes the cost for the capital, O&M and regulatory
fees including capital reinvestments over 20 years divided by the capacity duration. These
costs do not consider the variable costs, such as energy purchases.

Table 9.7: Lithium-ion Levelized Cost $/kW

Year Distribution Distribution Utility Scale Utility Scale Utility Scale
2022 238 378 173 318 552
2023 242 374 171 314 546
2024 246 372 169 312 542
2025 250 370 169 310 539
2026 254 369 168 309 538
2027 258 369 168 309 537
2028 262 369 168 308 536
2029 266 369 168 308 536
2030 271 370 168 309 537
2031 275 371 168 309 538
2032 280 372 169 310 539
2033 284 374 169 311 542
2034 289 377 170 313 544
2035 294 379 171 315 548
2036 298 382 172 317 551
2037 303 385 174 319 555
2038 308 388 175 322 559
2039 313 391 176 324 563
2040 319 394 177 326 567
2041 324 397 178 328 571
2042 329 400 180 331 575
2043 335 403 181 333 579
2044 340 406 182 335 583
2045 346 409 183 337 587

Flow Batteries
This IRP modeled vanadium and zinc bromide flow batteries. Other technologies are
beginning to enter the marketplace, including iron. Flow batteries have the advantage
over lithium-ion of not degrading over time leading to longer operating lives. The
technology consists of two tanks of liquid solutions that flow adjacent to each other past
a membrane and generate a charge by moving electrons back and forth during charging
and discharging. Avista assumed an acquisition size of 25 MW of capacity with 4-hours
in duration for each technology.

Capital costs are $1,633 per kW for the vanadium in 2020 and costs fall 44 percent by
2030. Zinc bromide’s capital cost are $1,837 per kW in 2020 falling 39 percent by 2030.
Fixed O&M costs are $57 per kW-year for vanadium and $64 per kW-year for zinc
bromide and increase with inflation. Round-trip efficiency for the vanadium is 70 percent
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 163 of 317
Chapter 9: Supply-Side Resource Options
Avista Corp 2021 Electric IRP 9-15
and for the zinc bromide is 67 percent. Given Avista’s recent experience with vanadium
flow batteries, these efficiency rates are highly dependent on the battery’s state of charge
and how quickly the system is charged or discharged. Table 9.8 shows the levelized cost
per kWh of capacity.

Table 9.8: Flow Battery Levelized Cost $/kWh of Capacity

Year Vanadium Zinc
2022 227 246
2023 222 244
2024 217 243
2025 217 242
2026 213 242
2027 213 242
2028 212 242
2029 212 242
2030 212 243
2031 211 243
2032 211 244
2033 211 245
2034 212 247
2035 213 248
2036 214 250
2037 215 251
2038 217 253
2039 219 255
2040 221 256
2041 222 258
2042 224 260
2043 226 261
2044 228 263
2045 229 265

Liquid Air
A new technology with promise to provide long duration and long service life is liquid air
storage. This is similar to compressed air storage, but rather than compressing the air,
the air is cryogenically frozen and stored in a tank to increase storage duration capability.
The conversion process requires a liquefier to liquefy the air for storage. It is possible to
use waste heat from existing natural gas-fired turbines to increase the efficiency of
liquefying the air molecules. This increases round-trip efficiencies from 65 percent to 75
percent. After the air is stored, it can later be used by pushing the air through an air
turbine.

Liquid air has not been widely used in the electric sector but relies on common technology
from other industries requiring liquefaction of gases. This experience in the technology
gives promise as a new technology that could benefit from short commercialization
periods. Avista assumed a 25 MW unit capacity with 400 MWh hours of storage (16
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Avista Corp 2021 Electric IRP 9-16
hours). Another advantage of this technology is the ability to add storage capacity by
adding more tanks while using the same turbine and liquefaction systems.

Avista estimates liquid air storage capital costs at $1,429 per kW (2020 dollars) and
increases with inflation due to the use of mature industrial technology. Fixed O&M is $26
per kW-year and carries a $3.06 per MWh variable charge. The levelized cost of the
storage is estimated to be $233 per kW for 2022 and future years increase with inflation.

Hydrogen/ Fuel Cell
The idea of using hydrogen in the energy sector has been a perennial option for the
distant future. Avista recognizes this technology as an avenue for long-duration energy
storage with the potential to store power to continuously run for up to several days.
Hydrogen would be delivered by pipeline, truck or rail and stored in tanks and then
converted back to power (and water) when needed using a fuel cell or hydrogen-fueled
turbine. This process would result in a 34 percent round trip efficiency. The ability to store
hydrogen in tanks similar to liquid air means medium term duration times can be obtained.
Significant R&D is being dedicated to hydrogen technologies in transportation and other
sectors which may result in reduced costs or increased operating efficiency. It is also
possible transportation and other sectors could utilize the electric power system to create
a cleaner form of hydrogen to offset gasoline, diesel, propane or natural gas. The concept
of offsetting natural gas led Avista to engage Black and Veatch to provide estimates for
renewable hydrogen options for the Natural Gas IRP. These assumptions and discussion
resulted from this study.

Most hydrogen today uses methane-reforming techniques to remove hydrogen from
natural gas or coal. This technology is primarily used in the oil and natural gas industries
but results in similar levels of greenhouse gas emissions from the combustion of the
underlying fuels absent sequestration or carbon capture. If green hydrogen is obtained
from “clean” energy through electrolysis, the amount of greenhouse gas emissions can
be greatly reduced. If renewable energy prices fall and there is an available water supply,
the operating cost of creating green hydrogen could also fall, however capital costs would
remain steady with significant technology enhancements.

Converting hydrogen back into power could be done by using a hydrogen fuel cell or
direct burning in a combustion turbine similar to natural gas-fired generation. Figure 9.2
shows the forecasted delivered price of hydrogen to a potential green hydrogen fuel
facility in Avista’s service territory. The development and delivery of green hydrogen is
estimated based on the projected cost of electrolyzer technology with reduction in costs
due to scaling and access to low cost renewable electric power.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Avista Corp 2021 Electric IRP 9-17
Figure 9.3: Wholesale Hydrogen Costs per Kilogram

The second step in the hydrogen concept is to convert the hydrogen back to power. For
this conversion, a 25 MW fuel cell would be assembled for utility scale needs. The
estimated capital cost for a fuel cell is $5,356 per kW with a forty-hour storage vessel plus
fixed O&M at $160 per kW-year. Table 9.9 shows the all-in levelized cost of hydrogen
including the fuel cell.

There are significant safety concerns relative to hydrogen that would have to be mitigated.
Hydrogen ignites more easily than gasoline or natural gas. Therefore, adequate
ventilation and leak detection are important elements in the design of a safe hydrogen
storage system. Hydrogen burns with a nearly invisible flame which requires special flame
detectors. Some metals become brittle when exposed to hydrogen, so selecting the
appropriate metal is important to the design of a safe storage system. Finally, appropriate
training in safe hydrogen handling would be necessary to ensure safe use. Appropriate
engineering along with safety controls and guidelines could mitigate the safety risk of
hydrogen but add to the high capital and operating costs of this resource option.

Hydrogen Turbine
Another hydrogen generation technology studied in this IRP is a hydrogen gas-fired
turbine with above ground storage. Avista assumes an 84 MW capacity with 3,356 MWh
hours of compressed storage (40 hours). An advantage of this technology is the ability to
add storage capacity by adding additional tanks and using the same turbine.

Avista estimates hydrogen gas turbine capital costs at $1,490 per kW (2020 dollars) and
increases with inflation due to the use of mature technology. Fixed O&M is $5 per kW-
year and carries a $4 per MWh variable charge. The levelized cost of the storage is
estimated to be $176 per kW for 2022 and future years increase with inflation.
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
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20
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2
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3
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K
i
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o
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r
a
m
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Chapter 9: Supply-Side Resource Options
Avista Corp 2021 Electric IRP 9-18
Table 9.9: Hydrogen Storage, Fuel Cell and Turbine Levelized Cost $/kWh

Year Fuel Cell (40-Turbine (40-
2022 837 176
2023 840 177
2024 844 177
2025 848 177
2026 853 177
2027 857 177
2028 861 177
2029 865 177
2030 870 177
2031 874 178
2032 879 178
2033 884 178
2034 889 178
2035 894 178
2036 899 178
2037 904 178
2038 909 179
2039 914 179
2040 920 179
2041 925 179
2042 931 179
2043 937 179
2044 943 180
2045 949 180

Woody Biomass Generation
Woody biomass generation projects use waste wood from lumber mills or forest
management and are considered renewable. In the biomass generation process, a
turbine converts boiler-created steam into electricity. A substantial amount of wood fuel
is required for utility-scale level generation. Avista’s 50 MW Kettle Falls Generation
Station consumes over 350,000 tons of wood waste annually or about 48 semi-truck loads
of wood chips per day. It typically takes 1.5 tons of wood to make one megawatt-hour of
electricity, but the ratio varies with the moisture content of the fuel. The viability of another
Avista biomass project depends on the long-term availability, transportation needs and
cost of the fuel supply. Unlike wind or solar, woody biomass can be stockpiled and stored
for later use. Many announced biomass projects fail due to the lack of a reliable long-term
fuel source.

Based on market analysis of fuel supply and expected use of biomass facilities, a new
facility could be envisioned as a wood-fired peaker. With high levels of intermittent
renewable generation, a wood-fired peaker could be constructed to generate during low
renewable output months or days. The capital cost for this type of facility would be $2,500
per kW plus O&M amounts of $26 per kW-year for fixed costs and $3.30 per MWh of
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 167 of 317
Chapter 9: Supply-Side Resource Options
Avista Corp 2021 Electric IRP 9-19
variable costs (2020 dollars). The levelized cost per MWh is $115 per MWh for a 2022
project.

Geothermal Generation
Geothermal energy provides predictable capacity and energy with minimal CO2
emissions (zero to 200 pounds per MWh). Some forms of geothermal technology extract
steam from underground sources to run through power turbines on the surface while
others utilize an available hot water source to power an Organic Rankine Cycle
installation. Due to the geologic conditions of Avista’s service territory, no geothermal
projects are likely to develop locally. Geothermal energy often struggles to compete
economically due to high development costs stemming from having to drill several holes
thousands of feet below the earth’s crust with no guarantee of reaching useable
geothermal resources. Ongoing geothermal costs are low, but the capital required for
locating and proving a viable site are significant. In Avista’s 2018 RFP, one geothermal
project was bid, leading Avista to reconsider this option as a possible resource in its IRPs.
The 2020 RFP did not receive any geothermal options. While a project was bid in the
past, geothermal resources must overcome the hurdles previously discussed. This IRP
estimates a future geothermal PPA at $81 per MWh in 2022 at the busbar.

Nuclear
Avista studies nuclear power options in IRP, but given the uncertainty of their economics,
regional political issues with the technology, U.S. nuclear waste handling policies and
Avista’s modest needs relative to the size of modern nuclear plants Avista is unlikely to
select a nuclear project in its preferred portfolio even if economic. Nuclear resources
could be in Avista’s future only if other utilities in the Western Interconnect incorporate
nuclear power into their resource mix and offer Avista a PPA or if cost effective small-
scale nuclear plants become commercially available.

The viability of nuclear power could change as national policy priorities focus attention on
decarbonizing the nation’s energy supply. The limited amount of recent nuclear
construction experience in the U.S. makes estimating construction costs difficult. Cost
projections in the IRP are from industry studies, recent nuclear plant license proposals
and the small number of projects currently under development. Modular nuclear design
could increase the potential for nuclear generation by shortening the permitting and
construction phase and making these traditionally large projects a better fit to the needs
of smaller utilities. Given this possibility, Avista included an option for small scale nuclear
power. The estimated cost for nuclear per MWh on a levelized basis in 2030 is $94 per
MWh assuming capital costs of $4,544 per kW (2020 dollars) as a PPA.

Other Generation Resource Options
Resources not specifically included as options in this IRP include cogeneration, landfill
gas, anaerobic digesters and central heating districts. This plan does not model these
resource options explicitly but continues to monitor their availability, cost and operating
characteristics to determine if state policies change or the technology becomes more
economically viable.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 168 of 317
Chapter 9: Supply-Side Resource Options
Avista Corp 2021 Electric IRP 9-20
Exclusion from the PRS analysis does not automatically exclude non-modeled
technologies from Avista’s future resource portfolio. The non-modeled resources can
compete with resources identified in the PRS through competitive acquisition processes
that always occur when a resource shortage is indicated, and the Company seeks
resources to fill those needs. Competitive acquisition processes identify technologies to
displace resources otherwise included in the IRP strategy. Another possibility is
acquisition through a PURPA contract. PURPA provides developers the ability to sell
qualifying power to Avista at set prices and terms7 outside of the RFP process.

Landfill Gas Generation
Landfill gas projects generally use reciprocating engines to burn methane gas collected
at landfills. The costs of a landfill gas project depend on the site specifics of a landfill. The
Spokane area had a project at one of its landfills, but it was retired after the fuel source
depleted to an unsustainable level. Much of the Spokane area uses the Spokane Waste
to Energy Plant instead of landfills for solid waste disposal. Nearby in Kootenai County,
Idaho, the Kootenai Electric Cooperative developed the 3.2 MW Fighting Creek Project.
Using publicly available costs and the NPCC estimates, landfill gas resources are
economically promising, but are often limited in their size, quantity and location. Many
landfills are considering cleaning the landfill gas to create pipeline quality gas due to low
wholesale electric market prices. This form of renewable natural gas has become an
option for utilities to offer a renewable gas alternative to customers. This form of gas and
the duration of the supply depends on the on-going disposal of trash, otherwise the
methane could be depleted in six to nine years.

Anaerobic Digesters (Manure or Wastewater Treatment)
The number of anaerobic digesters is increasing in the Northwest. These plants typically
capture methane from agricultural waste, such as manure or plant residuals, and burn the
gas in reciprocating engines to power generators or directly inject a cleaned fuel into the
natural gas pipeline. These facilities tend to be significantly smaller than most utility-scale
generation projects and are often less than five megawatts. Most digester facilities are
located at large dairies and cattle feedlots. A survey of Avista’s service territory found no
large-scale livestock operations capable of implementing this technology.

Wastewater treatment facilities can host anaerobic digesting technology. Digesters
installed when a facility is initially constructed helps the economics of a project
significantly, although costs range greatly depending on system configuration. Retrofits
to existing wastewater treatment facilities are possible but tend to have higher costs.
Many projects offset energy needs of the facility, so there may be little, if any, surplus
generation capability. Avista currently has a 260-kW wastewater system under a PURPA
contract with a Spokane County wastewater facility.

Small Cogeneration
Avista has few industrial customers with loads significantly large enough to support a
cogeneration project. If an interested customer developed a small cogeneration project,
it could provide benefits including reduced transmission and distribution losses, shared

7 Rates, terms, and conditions are available at www.avistautilities.com under Schedule 62.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Avista Corp 2021 Electric IRP 9-21
fuel, capital and emissions costs, as well as credit toward Washington’s EIA efficiency
targets.

Another potentially promising option is natural gas pipeline cogeneration. This technology
uses waste-heat from large natural gas pipeline compressor stations. Few compressor
stations exist in Avista’s service territory, but the existing compressors in our service
territory have potential for this generation technology. Avista has discussed adding
cogeneration with pipeline owners, but no project has been deemed feasible. A big
challenge in developing any new cogeneration project is aligning the needs of the
cogenerator with the utility need for power. The optimal time to add cogeneration is during
the creation or retrofit of an industrial process, but the retrofit may not occur when the
utility needs new capacity. Another challenge to cogeneration within an IRP is estimating
costs when host operations drive costs for a project. The best method for the utility to
acquire this technology is through the PURPA process or through a future RFP.

Coal
The coal generation industry is at a crossroads. In many states, like Washington, new
coal-fired plants are extremely unlikely due to current policy, emission performance
standards and the shortage of utility scale carbon capture and storage projects. The risks
associated with future carbon legislation and projected low natural gas and renewables
costs make investments in this technology highly unlikely. It is possible in the future there
will be permanent carbon capture and sequestration technology at price points to
compete with alternative fuels. Avista will continue to monitor this development for future
IRPs.

Heating Districts
Historically heating districts were preferred options to heat population dense city centers.
This concept relies on a central facility to either create steam or hot water then distribute
via a pipeline to buildings to provide end use space and water heating. Historically, Avista
provided steam for downtown Spokane using a coal-fired steam plant. This concept is still
used in many cities in the U.S. and Europe including Seattle, WA. Developing new heating
districts requires the right circumstances, partners and long-term vision.

These requirements recently came together in a new concept of central heating districts
being tested by a partnership between Avista and McKinstry in the Spokane University
District, also called the Eco-District. The Hub facility contains a central energy plant to
generate, store and share thermal and electrical energy with a combination of heat
pumps, boilers, chillers, thermal and electrical storage. The Hub controls all electric
consumption for the campus and balances this against the needs of both the development
and the grid. Future buildings within the district will be served by the Hub’s central energy
plant, expanding the district’s shared energy footprint. A part of the Eco-District
development will involve studying the costs and benefits of this configuration. The
success of the district will determine how it will be implemented in the future for Avista’s
customers.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Bonneville Power Administration
For many years, Avista received power from the Bonneville Power Administration (BPA)
through a long-term contract as part of the settlement from WNP-3. Most of the BPA’s
power is sold to preference customers or in the short-term market. Avista does not have
access to power held for preference customers but engages BPA on the short-term
market. Avista has two other options for procuring BPA power. The first is using the New
Resource NR rate. BPA’s power tariff outlines a process for utilities to acquire power from
BPA using this rate for one year at a time. As of the publishing of this IRP, the NR rate is
$79.80 per MWh8. Since this offering is short-term and variable, Avista does not consider
it a viable long-term option for planning purposes, however, it is a viable alternative for
short-run capacity needs. The other option to acquire power from BPA is to solicit an offer.
BPA is willing to provide prices for periods of time when it believes it has excess power
or capacity. This process would likely parallel an RFP process for future capacity needs
and likely take place after current agreements with public power customers end in 2027.

Existing Resources Owned by Others
Avista has purchased long-term energy and capacity from regional utilities in the past,
specifically the Public Utility Districts in Mid-Columbia region and has a tolling agreement
for the Lancaster Generating Station. Avista contracts are discussed in Chapter 4, but
extensions or new agreements could be signed. If utilities are long on capacity, it is
possible to develop agreements to strengthen Avista’s capacity versus load position.
Since these potential agreements are based on existing assets, prices are dependent on
future markets. Avista is modeling for this IRP the possibility of an up to 75 MW extension
of existing hydro agreements, but the cost and actual quantities available in the future are
unknown. Avista could acquire or contract for energy and capacity of other existing
facilities without long term agreements. Avista anticipates these resources will be offered
into future RFPs and may replace any resources selected in this IRP.

Renewable Natural Gas
Avista did not model the option to use renewable natural gas (RNG) for electric generation
in this IRP. RNG is methane gas sourced from waste produced by dairies, landfills,
wastewater treatment plants and other facilities. The amount of RNG is limited by the
output of the available processes. The amount of greenhouse gas emissions the RNG
offsets differs depending upon the source of the gas and the duration of the methane
abatement used. Avista considers the cost-effective use of this fuel type in its Natural Gas
IRP and believes its best use is to reduce emissions from the direct use of natural gas
rather than use as a fuel in natural gas-fired turbines due to higher end-use efficiency in
customers’ homes.

Hydro Project Upgrades and Options
Avista continues to upgrade its hydro facilities as shown in Figure 9.3. The latest hydro
upgrade added 10 megawatts to the Nine Mile Falls Development in 2016. Avista added
46.8 aMW of incremental hydro energy between 1992 and 2016. Upgrades completed
after 1999 can qualify for the EIA, thereby reducing the need for additional renewable

8 https://www.bpa.gov/Finance/RateInformation/Pages/Current-Power-Rates.aspx.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Avista Corp 2021 Electric IRP 9-23
energy options. Further, any upgrade can qualify for CETA if it meets the requirements
as a clean energy resource.

Construction of the Spokane River hydro project occurred in the late 1800s and early
1900s, when the priority was to meet then-current loads. The developments using the
technology of the time do not capture most river flows. In 2012, Avista reassessed its
Spokane River Project to evaluate opportunities to capture more of the streamflow. The
goal was to develop a long-term strategy and prioritize potential facility upgrades. Avista
evaluated five of the six Spokane River hydro developments and estimated costs for
generation upgrade options. Each upgrade option would qualify for the EIA renewable
energy goal. These studies were part of the 2011 and 2013 IRP Action Plans and results
appear below. Each of these upgrades are major engineering projects, taking several
years to complete and requiring major changes to the FERC licenses and the project’s
non-consumptive water rights. The upgrades will compete against other renewable
options when more renewables are required or developed as Avista considers the most
effective management plans for these existing projects.

Figure 9.4: Historical and Planned Hydro Upgrades

Post Falls
This IRP assumes a refurbishment of Post Falls by 2026. Avista studied this upgrade in
the 2020 IRP and it was found to be cost effective. Avista is continuing to engineer and
plan for this refurbishment and assumptions will likely change over time, but for planning
purposes Avista assumes an additional 3.8 MW of incremental winter capacity and 4
aMW of incremental clean energy from this upgrade.

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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 172 of 317
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Avista Corp 2021 Electric IRP 9-24
Long Lake Second Powerhouse
Avista studied adding a second powerhouse at Long Lake over 30 years ago by using
the small arch or saddle dam located on the south end of the project site. This project
would be a major undertaking and require several years to complete, including major
changes to the Spokane River FERC license and water rights. In addition to providing
customers with a clean energy source, this project could help reduce total dissolved gas
levels by reducing spill at the project and providing incremental capacity to meet peak
load growth.

The 2012 study considered three alternatives. The first involved replacing the existing
four-unit powerhouse with four larger units totaling 120 MW, increasing capacity by 32
MW. The other two alternatives considered development of a second powerhouse with a
penstock from a new intake structure located downstream of the existing saddle dam.
One powerhouse option was a single 68 MW turbine project. The second option was a
two-unit 152 MW project. The best alternative in the study was to add the single 68 MW
unit. Table 9.10 shows upgrade costs and characteristics. Avista does not believe this
upgrade will meet the requirements of a qualifying clean energy project for CETA,
consequently the upgrade is not included in this resource plan as it was in the 2020 IRP.

Cabinet Gorge Second Powerhouse
Avista is exploring the addition of a second powerhouse at the Cabinet Gorge site to
mitigate total dissolved gas and produce additional electricity. A new 110 MW
underground powerhouse would benefit from an existing diversion tunnel around the dam
built during original construction. Unfortunately, this resource would not have any peak
capacity credit due to the water right limitations of the license. The resource only creates
additional energy during spring runoff.

Table 9.10: Hydroelectric Upgrade Options

Resource Long
Lake
Cabinet
Gorge
Incremental Capacity (MW) 68 110
Incremental Energy (MWh) 202,531 161,885
Incremental Energy (aMW) 23.1 9.2
Peak Credit (Winter/ Summer) 100/100 0/0
Capital Cost ($2020 Millions) $162 $255
Levelized Energy Cost ($2022/MWh) $98 $186

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 173 of 317
Chapter 9: Supply-Side Resource Options
Avista Corp 2021 Electric IRP 9-25
Thermal Resource Upgrade Options
For the last several IRPs, Avista investigated opportunities to add capacity at existing
facilities. These projects have been implemented when cost effective. Avista is modeling
three potential options at Rathdrum CT and an option at Kettle Falls Generating Station.
Since pricing is sensitive to third-party suppliers, concept overviews with no costs are
presented in this section. Estimated costs including the portfolio modeling is discussed in
Chapter 11.

Rathdrum CT Supplemental Compression
Supplemental compression is a new technology to increase airflow through the CT
compressor thereby increasing machine output. This upgrade could increase Rathdrum
CT capacity by 24 MW.

Rathdrum CT 2055 Uprates
By upgrading certain combustion and turbine components, the firing temperature can
increase to 2,055 degrees from 2,020 degrees providing a 5 MW increase in output.

Rathdrum CT Inlet Evaporation
Installing a new inlet evaporation system could increase the Rathdrum CT capacity by 17
MW on a peak summer day, but no additional energy is expected during winter months.

Kettle Falls Turbine Generator Upgrade
The Kettle Falls plant began operation in 1983. In 2025, the generator and turbine will be
42 years old and at the end of its expected life. Avista could spend additional capital and
upgrade the unit by 12 megawatts rather than replace it with in-kind technology.

Intermittent Generation Costs
Intermittent generation resources such as wind and solar require other resources to help
balance the unpredictable energy supply. This results in a cost required by shifting from
otherwise more efficient operations. This is challenging for Avista because the cost could
be the difference of running stored water hours later compared to now. Avista began
studying these costs on its system in 2007. This analysis created the methodology the
ADSS model now uses to not only study the costs of the intermittent resources, but also
better equip our real-time operations team with information to use in managing when to
dispatch resources. For this IRP, wind adds approximately $5 per MWh in operating cost
inefficiencies and solar $1.80 per MWh based on the 2007 study. Avista’s 2007 study9 is
still relevant due to scenario analysis performed resulting in pricing similar to today’s
prices along with a similar resource portfolio. Avista believes these costs will increase
with additional generation on the system and plans to update its intermittent cost study in
2021 and incorporate results in future IRPs. . Participation in an Energy Imbalance Market
(EIM) can reduce these costs by up to 40 percent based on information provided by the
CAISO.

9 Avista engaged a third-party to update these studies as well as determine how these integration costs will
be impacted in the future by EIM.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Another cost to consider when adding intermittent generation is the capacity value for
reliability. Intermittent resources add additional load following requirements when
operating in the event the resource loses power. For this additional requirement, Avista’s
ELCC studies require a 10 percent increase in held reserves for the produced energy
each hour.

Sub Hourly Resource and Ancillary Services Benefits
Many of the resources discussed in this chapter may provide reliability benefits to the
electrical system beyond traditional energy and capacity due to intra hour needs and
system reliability requirements. Some resources can provide reserve products such as
frequency response or contingency reserves. Avista is required to hold generating
reserves of 3 percent of load and 3 percent of on-line generation. This means resources
need to be able to respond in 10 minutes in the event of other resource outages on the
system. Within the reserve requirement, 24 MW must be held as frequency response to
provide instantaneous response to correct system frequency variations. In addition to
these requirements, Avista must also hold capacity to help control intermittent resources
and load variance, this is referred to as load following and regulation. The shorter time
steps minute-to-minute is regulation and longer time steps such as hour-to-hour is load
following. Together these benefits consist of ancillary services for the purposes of this
IRP.

Many types of resources can help with these requirements, specifically storage projects,
natural gas peakers and hydro generation. Some DR options may help in the future as
well. The benefits these projects bring to the system greatly depend on many external
factors including other “capacity” resources within the system, the amount of variation of
both load and generation, market prices, market organization (i.e. EIM) and hydro
conditions. Internal factors also play a role, such as the ability for the resource to respond
in speed and quantity. Avista conducted a study on its Turner Energy Storage project
along with the Pacific Northwest National Lab to understand the operating restrictions of
the technology. For example, if the battery is quickly discharged, the efficiency lowers
and depending on the current state of charge the efficiency is also affected. These
nuances make it more difficult to model in existing software systems.

Avista will continue studying the benefits of energy storage by modeling additional
scenarios including price, water year and level of renewable penetration. It will also need
to study the benefits of using a sub-hourly model rather than using variability estimates
within the hour. Avista is refining the ADSS model to provide this complete analysis
although Avista does not expect more detailed analysis to change the current results of
these studies. Avista presented results from two studies regarding the potential analysis
with the ADSS system. These analyses were completed using existing markets and
showed the potential to provide benefits from new resources with flexibility. Although, as
Avista enters a future with additional on-system renewables and an EIM, these estimates
will need to be revised. Table 9.11 outlines the assumed values for Ancillary Service or
within hour benefits for new construction projects. These estimates also apply to
distributed energy resources in the event they are able to respond to utility signals.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 175 of 317
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Avista Corp 2021 Electric IRP 9-27
Table 9.11: Ancillary Services & Sub-hourly Value Estimates (2020 dollars)

Resource $/kW-yr
Natural gas-fired CT/reciprocating engine 1.00
Lithium-ion battery 4.74
Lithium-ion battery connected to solar 1.50
Pumped hydro 4.74
Flow battery 1.74
Liquid Air 0.50

Resource Peak Credit and ELCC Analysis
Avista conducted substantial research and spent considerable time studying the impact
of the effect of different resources on resource adequacy for this IRP and the 2020 IRP.
Avista uses an Equivalent Load Carrying Capability (ELCC) analysis to determine the
appropriate reliability benefit each resource provides to the system. Avista uses a peak
credit to show the equivalent value of a resource to its “surrogate” natural gas turbine
resource. Avista learned the quantity, location and mixture of resources has a substantial
impact on the benefit each resource provides. For example, 4-hour duration storage can
provide high levels of resource adequacy in small quantities because it has other
resources to assist in its recharging; but as the proportion of storage gets larger, there is
not enough energy to refill the storage device for later dispatch as shown in the E3 study
for resource adequacy for the northwest10. When coupled with renewable energy storage,
the combined resources may increase Avista’s resource adequacy, but this depends on
how much energy can be stored and the amount produced in critical periods. Higher levels
of penetrations for renewables may lower their effect on resource adequacy.

To complete the analysis, Avista used 1,000 simulations of hydro, load, wind and forced
outage rates to estimate the contribution for different types of resources available to meet
its peak. This is measured by the resources ability to reduce Loss of Load Probability
(LOLP) using the Avista Reliability Assessment Model (ARAM). ARAM simulates Avista’s
system on an hourly basis for a future year where resource deficits occur (i.e. 2030). Each
of the simulations use a different potential configuration of the system assumptions to
account for uncertainty of weather conditions and resource availability. For example,
historical weather years are randomly input into the model to change loads and resource
capability such as hydro availability and the maximum generation capability of thermal
units. The model’s objective is to determine if there are adequate resources available
from the Avista resource stack to meet load and reserve requirements each hour. The
model also has the ability to purchase energy from the wholesale market. This market is
limited to 330 MW in days with weather conditions exceeding the 99th percentile,
otherwise the model assumes 500 MW of market availability. Any hour that cannot meet
its load or reliability requirements is considered a loss of load event.

Given the 2030 year is a resource deficit year, the model includes additional new natural
gas-fired CTs to meet future load obligations. In total between existing and “new” CTs,
the system has sufficient resources equal to meet the 16 percent planning margin needed

10 2020 IRP Appendix F, Resource Adequacy in the Pacific Northwest, page 54.
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above the expected peak load. To determine the peak credit, the “new” gas-fired turbines
are removed in total or in part and replaced with each of the resources in Table 9.12
individually. The model runs through iterative cycles to determine the amount of a
resource needed to achieve equal reliability as the natural gas-fired CTs from a LOLP
perspective. This means each resource is added to the model until the LOLP returns to
the same level as the CT resource alternative. The percentage shown in the table is the
percent of natural gas turbines assumed offset by the replacement resource. For
example, if a northwest wind resource replaced a natural gas CT resource, it would not
be replaced one for one, but rather each 5 MW reduction in natural gas CTs would require
100 MW of the additional wind resource to equal the same LOLP. The lower values of
peak capacity credits are due to the resource either not reliably providing energy during
times of system need or the resource running out of energy over the duration of the high
load event, such as with storage. In the case of the storage resource, during a peak load
event when all resources are needed to respond to load during the day, the storage
resource may be able to provide energy for four hours, but fails to continue energy
delivery once the battery is drained and may not be able to recharge until either system
or market energy is available. Due to Avista’s load profile of not only winter peaking, but
significantly higher daily winter loads, storage resources require longer durations to
replace traditional energy resources able to serve loads throughout the day.

Table 9.12: Peak Credit or Equivalent Load Carrying Capability Credit

Resource Peak Credit
Northwest solar 2
Northwest wind 5
Montana wind11 100-200 MW 35 to 28
Hydro w/ storage 60-100
Hydro run-of-river 31
Storage 4 hr duration 15
Storage 8 hr duration 30
Storage 12 hr duration 58
Storage 16 hr duration 60
Storage 24 hr duration 65
Storage 40 hr duration 75
Storage 70 hr duration 90
Demand response 60
Solar + 4 hr Storage12 17
Solar + 2 hr Storage13 12

11 Net of transmission losses. Montana wind peak credits decline with additional capacity, the first 200 MW
is 35 percent, the next 100 MW is 30 percent, and another 100 MW is 28 percent. Avista does not assume
any Montana wind beyond 400 MW.
12 This assumes the storage resource may only charge with solar. This specific option was not modeled
within the PRS and is shown as a reference only. Avista only modeled solar plus storage where the storage
resource could be charged with non-solar as well to reflect long-term utility operations.
13 Avista limited solar plus storage to these two scenarios; many other options are likely including different
durations and storage to solar ratios. Specific configurations would need to be studied to validate peak
credits for those configurations.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 177 of 317
Chapter 9: Supply-Side Resource Options
Avista Corp 2021 Electric IRP 9-29
Other Environmental Considerations
All generating resources have an associated greenhouse gas emissions profile, either
when it produces energy, during operations, when constructed, retired, or all of the above.
For this IRP, Avista modeled associated emissions with the production of energy as well
as emissions associated with the manufacturing and construction of the facility where
emissions information was available, such as from the National Renewable Energy
Laboratory (NREL) data for greenhouse gas emissions related to construction and
operations.

This IRP also includes upstream greenhouse gas emissions from natural gas. Natural
gas is assumed to directly emit 119 pounds of equivalent greenhouse gases per
dekatherm when including the other gases within the supply. In addition to those
emissions, there could be upstream emissions from the drilling process and the
transportation of the fuel to the plant also known as fugitive emissions. While not required
by the final CETA rules, this IRP includes these emissions priced at the social cost of
carbon for the Washington customer portion of resource optimization. The additional
emissions are assumed to be 9.8 percent added to the emissions from dispatch. This
percentage accounts for both upstream methane leakage and combusted natural gas in
the supply chain. The combusted upstream natural gas is estimated to be 0.77 percent14
assuming a Canadian sourced natural gas supply. The remaining percentage is derived
from estimated methane releases using a 34-year conversion factor from methane to CO2
equivalent emissions.

Social Cost of Carbon
The social cost of carbon is included for thermal resource project additions along with
projected emissions reduction from energy efficiency for Washington’s load obligations.
The social cost of carbon pricing is shown in Figure 9.4. Avista uses the pricing method
and the 2.5 percent discount rate identified by the Washington Commission for CETA.
The prices are inflated from 2007 to 2020 using the Bureau of Economic Analysis inflation
data and then inflated at 2.11 percent each year thereafter.

PRiSM, Avista’s portfolio optimization model, uses the social cost of carbon as a cost
adder to Washington’s share of greenhouse emitting resources for both existing and new
resource options and the associated regional emission reductions from energy efficiency.
Any emissions associated with the operations and construction is also included in the
social cost of carbon analysis. Avista does not use the social cost of carbon pricing for
market transactions including purchases for storage as it had done in the 2020 IRP per
the CETA requirements only targeting these costs for intermediate and long-term
resources. After review of Section 14 of the CETA, focusing on these costs shall be
included for evaluating energy efficiency programs and evaluating intermediate term and
long-term resource options. Given this section of the law excludes short term
transactions, Avista chose not to include this cost for market transactions although a

14 The emission rate is from recent environment impact studies for the PSE Tacoma LNG plant, Kalama
Manufacturing and Export Facility.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 178 of 317
Chapter 9: Supply-Side Resource Options
Avista Corp 2021 Electric IRP 9-30
scenario is included in Chapter 12 of this IRP to reflect the difference in the plan if these
costs were included.
Figure 9.5: Social Cost of Carbon

Other Environmental Considerations
There are other environmental factors involved when siting and operating power plants.
Avista considers these costs in the siting process. For example, new hydro projects or
modifications to existing facilities must be made in accordance with their operating
license. If new or upgraded facilities require operations outside this license, the license
would be reopened. When siting solar and wind facilities, developers must have solicit
and receive approvals from local, state and federal governing boards or agencies to
ensure all laws and regulations are met.

If Avista sites a new natural gas-fired facility, it will have to meet all state and local air
requirements for its air permit. Requirements are at levels these governing bodies find
appropriate for their communities. Currently, Avista is not evaluating emissions costs
outside of these considerations.

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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 179 of 317
Chapter 10: Market Analysis
Avista Corp 2021 Electric IRP 10-1
Market Analysis

Energy policy in the Western Interconnect is shifting toward clean generation. Several
states, including Washington and California, already have 100 percent clean energy
goals. These policy changes dramatically impact the wholesale power market. Previous
IRPs focused on carbon pricing methodologies driving wholesale power prices upward.
At this time, it does not appear policymakers will pursue direct carbon mitigation policies.
Rather energy policies now focus on 100 percent clean energy to achieve carbon
reductions. This approach drives wholesale prices lower and may lead to the build-out of
storage resources although traditional natural gas-fired generation is still needed to
prevent significant price volatility and prevent reliability events.

Fundamental market analysis is important to support the resource strategy selected to
serve Avista’s customers over the next 20 plus years. Avista uses forecasts of future
market conditions to optimize its resource portfolio options. The Company uses electric
price forecasts to evaluate the net operating margin of each supply- and demand-side
option for comparative analysis between each resource type. The model tests each
resource in the wholesale marketplace to understand its profitability, dispatch, fuel costs,
emissions, curtailment and other operating characteristics.

Avista conducts the wholesale market analysis using the Aurora model by Energy
Exemplar. The model includes generation resources, load estimates and transmission
links within the Western Interconnect. This chapter outlines the modeling assumptions
and methodologies for this IRP and includes Aurora’s primary function of electric market
pricing (Mid-Columbia for Avista), as well as operating results from the analysis. The
Expected Case is a forecast defined using the best available information on policies,
regulations and resource costs under average conditions. This chapter also presents the
results of four additional pricing scenarios to better understand changes to the electric
market if natural gas prices significantly increase or decrease from the forecast, climate
Section Highlights
 Solar and wind dominate future generation across the west while natural gas
and increasing amounts of storage will ensure resource adequacy as more coal
plants shut down.
 By 2045, 91 percent of generation in the Pacific Northwest will be carbon free,
up from approximately 70-80 percent today depending on hydro conditions.
 Greenhouse gas emissions will fall to historic lows with the expansion of
renewables and continued coal plant retirements. By 2045, expected emissions
will be 64 percent less than in 1990.
 The 24-year wholesale electric price forecast (2022-2045) is $27.13 per MWh.
Expansion of renewables reduces mid-day prices, but evening and nighttime
prices will be at a premium compared to today’s pricing.
 Natural gas prices continue to remain low; for example, the levelized price at
Stanfield (2022-2045) is $3.45 per dekatherm.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 180 of 317
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Avista Corp 2021 Electric IRP 10-2
change impacts to loads and hydro conditions, and the effects of a national greenhouse
gas pricing mechanism.

Electric Marketplace
Avista simulates the entire Western Interconnect electric system for its IRP planning;
shown as WECC1 in Figure 10.1. The rest of the U.S. and Canada are in separate
electrical systems. The Western Interconnect includes the U.S. system west of the Rocky
Mountains plus two Canadian provinces and the northwest corner of Mexico’s Baja
peninsula.

The Aurora market simulation model represents each operating hour between 2022 and
2045. It simulates both load and generation dispatch for sixteen regional areas or zones
within the west. Avista’s load and most of its generation is in the Northwest zone identified
in Table 10.1. Each of these zones include connections to other zones via transmission
paths or links. These links allow generation trading between zones and reflect operational
constraints of the underlying system, but do not model the physics of the system as a
power flow model. Avista focuses on the economic modeling capabilities of the Aurora
platform to understand resource dispatch and market pricing effects resulting in a
wholesale electric market price forecast for the Northwest zone or Mid-Columbia
marketplace.

The Aurora model estimates its electric prices using an hourly dispatch algorithm to match
the load in each zone with the available generating resources. Resources are selected to
dispatch after considering fuel availability, fuel cost, operations and maintenance cost,
dispatch incentives/disincentives and operating constraints. The marginal cost of the last
generating resource needed to meet area load becomes the electric price. The IRP uses
these prices to value each resource (both supply and load side) option and select from
among them to achieve a least reasonable cost plan meeting all load and reliability
obligations. Avista also conducts stochastic analyses for its price forecasting, where
certain assumptions are drawn from 500 distributions of potential inputs. For example,
each forecast randomly draws from an equally weighted probability distribution of the 80-
year hydro record.

The next several sections of this chapter discuss the assumptions used to derive the
wholesale electric price forecast, resulting dispatch and greenhouse gas emissions
profiles for the west for the 500 stochastic studies.

1 WECC is the Western Electrical Coordinating Council. It coordinates reliability for the Western
Interconnect.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 181 of 317
Chapter 10: Market Analysis
Avista Corp 2021 Electric IRP 10-3
Figure 10.1: NERC Interconnection Map

Table 10.1: AURORA Zones

Northwest- OR/WA/ID/MT Southern Idaho
Utah Wyoming
Eastern Montana Southern California
Northern California Arizona
Central California New Mexico
Colorado Alberta
British Columbia South Nevada
North Nevada Baja Mexico

Western Interconnect Loads
Each of the sixteen zones in Aurora require hourly load data for all 24 years of the forecast
plus 500 different stochastic studies for weather variation. Future loads may not resemble
past loads from an hourly shape point of view due to the continual increase in EVs and
rooftop solar. Changes in energy efficiency, demand curtailment/demand response,
population migration and economic activity increase the complexity. While each of these
drivers are important to the forecast of power pricing, it takes a large amount of analytical
time to estimate or track these macro effects over the region. Avista uses the following
methods to derive its regional load forecast for power price modeling to account for these
complexities.

Avista begins with Energy Exemplar’s demand forecast included with the Aurora software
package. This forecast includes an hourly load shape for each region along with annual
changes to both peak and energy values. The hourly load shape uses historical data for
each balancing area and the growth rates from publicly available forecast information for
each region. Figure 10.2 shows this base forecast as the black dotted line. Western
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 182 of 317
Chapter 10: Market Analysis
Avista Corp 2021 Electric IRP 10-4
Interconnect load grows 0.51 percent per year. Avista adjusts this initial forecast to
account for changes in EV penetration and net-metered generation, including rooftop
solar. Annual EV load grows at 12.5 percent and net-metered generation grows at 2.4
percent2. These adjustments increase the load forecast growth rate to approximately 0.85
percent per year. Within the year, the hourly load shapes adjust to reflect charging
patterns of both residential and commercial vehicles in addition to most net-metered
generation being modeled as fixed roof mount solar panels.

Figure 10.2: 24-Year Annual Average Western Interconnect Load Forecast

Regional Load Variation
Several factors drive load variability. The largest short-run driver is weather. Long-run
economic conditions, like the Great Recession, tend to have a larger impact on the load
forecast. IRP loads increase on average at the levels discussed earlier in this chapter,
but risk analyses emulate varying weather conditions and base load impacts. Avista
continues with its previous practice of modeling load variation using FERC Form 714 load
data from 2015 to 2019. To maintain consistent west coast weather patterns, statistically
significant correlation factors between the Northwest and other Western Interconnect load
areas represent how electricity demand changes together across the system. This
method avoids oversimplifying Western Interconnect loads. Absent the use of
correlations, stochastic models may offset changes in one variable with changes in
another, virtually eliminating the possibility of broader load excursions witnessed by the
electricity grid. The additional accuracy from modeling loads this way is crucial for
understanding wholesale electricity market price variation as well as the value of peaking

2 Avista uses forecasts provided by IHS Markit to assist in the development of these forecasts.
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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 183 of 317
Chapter 10: Market Analysis
Avista Corp 2021 Electric IRP 10-5
resources and their use in meeting system variation. The load correlation values are
summarized in Tables 10.2 through 10.5. Data reported as “Mix” or “Not Sig” in the tables
indicates data for that region and time period either was not statistically correlated with
Northwest loads or the annual correlations varied between correlated and inversely
correlated. In either case, no correlation was used for results with “Mix” or “Not Sig”.
These load variations form the basis for load changes in each of the 500 simulations of
the electric price forecast.

Table 10.2: January through June Load Area Correlations

Area Jan Feb Mar Apr May Jun
Alberta Mix Mix 28%Mix Mix Mix
Arizona Not Sig 28%Not Sig Not Sig 9%Not Sig
Avista 95%96%92%78%50%90%
British Columbia 87%91%93%67%Mix 67%
California 8%Not Sig Not Sig Not Sig Mix Not Sig
CO-UT-WY 61%Not Sig Not Sig Not Sig Mix Mix
Montana 64%75%66%8%Mix 16%
New Mexico Mix Mix Mix Mix Not Sig Mix
North Nevada Not Sig 83%64%Mix Mix 18%
South Idaho 67%85%69%Mix Mix 35%
South Nevada Not Sig 10%Mix Not Sig 9%Not Sig

Table 10.3: July through December Load Area Correlations

Area Jul Aug Sep Oct Nov Dec
Alberta Mix Mix Mix Mix 10%Mix
Arizona Mix Mix 26%-8%Mix Mix
Avista 89%81%86%88%89%92%
British Columbia 77%72%37%76%87%85%
California 36%8%50%-33%Mix Not Sig
CO-UT-WY Mix Mix 9%Not Sig Not Sig Not Sig
Montana Not Sig 8%9%54%30%49%
New Mexico Not Sig Mix Mix 8%19%Mix
North Nevada Not Sig Not Sig 59%65%72%Not Sig
South Idaho Not Sig 57%59%62%73%65%
South Nevada Mix Mix 20%-17%Mix Mix

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 184 of 317
Chapter 10: Market Analysis
Avista Corp 2021 Electric IRP 10-6
Table 10.4: Area Load Coefficient of Determination (Standard Deviation/Mean)

Area Jan Feb Mar Apr May Jun
Alberta 2.9%2.4%2.9%1.8%4.0%4.8%
Arizona 6.6%7.6%4.9%7.5%11.0%10.2%
Avista 8.6%9.2%7.9%5.9%4.7%7.1%
British Columbia 5.8%7.3%6.9%5.6%3.7%4.2%
California 5.8%5.6%5.8%6.6%8.2%11.3%
CO-UT-WY 4.3%6.4%5.2%4.1%5.0%9.3%
Montana 6.0%11.3%9.8%7.2%6.5%6.0%
New Mexico 5.5%5.9%4.4%5.2%7.9%9.3%
Northern Nevada 3.8%6.2%5.6%4.8%4.5%7.0%
Pacific Northwest 9.1%9.7%8.4%5.2%4.0%5.4%
South Idaho 8.4%8.2%7.4%7.3%10.2%11.7%
South Nevada 4.5%6.1%4.4%9.9%14.3%13.2%

Table 10.5: Area Load Coefficient of Determination (Standard Deviation/Mean)

Area Jul Aug Sep Oct Nov Dec
Alberta 3.0%2.2%2.2%2.8%3.1%3.6%
Arizona 7.7%7.2%12.2%7.6%3.3%5.1%
Avista 8.1%7.6%5.7%6.6%7.0%7.0%
British Columbia 4.7%4.7%3.4%4.4%5.5%6.0%
California 9.7%7.9%10.7%7.5%5.6%5.4%
CO-UT-WY 6.8%6.7%7.9%5.4%5.7%4.4%
Montana 7.0%8.3%7.7%8.8%8.6%5.0%
New Mexico 6.6%7.5%8.3%7.8%5.3%5.3%
Northern Nevada 6.1%5.4%6.9%4.5%5.8%4.0%
Pacific Northwest 6.4%6.4%4.9%5.8%7.3%7.1%
South Idaho 7.0%7.3%15.0%6.7%7.9%6.8%
South Nevada 8.8%8.3%15.5%9.4%3.2%3.9%

Generation Resources
The Aurora model needs a forecast of generation resources to compare and dispatch
against the load forecast for each hour. A generation availability forecast includes the
following mean components:

 Resources currently available;
 Resources retiring;
 New resources for capacity and load service;
 New resources for renewable energy compliance; and,
 Fuel prices, fuel availability and operating availability.

Aurora contains a database of existing generating resources with the location, size and
estimated operating characteristics for each resource. When a resource has a publicly
scheduled retirement date or is part of an approved provincial phase-out plan, it is retired
for modeling purposes on the expected date. Avista does not project retirements beyond
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 185 of 317
Chapter 10: Market Analysis
Avista Corp 2021 Electric IRP 10-7
those with publicly stated retirement dates or phase out plans. Rather, plants that become
less economic in the forecast dispatch fewer hours. Several coal plant retirements have
or are expected to occur in the Northwest during this IRP, including Boardman, Colstrip
Units 1 and 2, North Valmy and Centralia. Figure 10.3 shows the total retirements
included in the electric price forecast. Approximately 26,000 MW of coal, 7,000 MW of
natural gas, 4,758 MW of nuclear, and 750 MW of other Western Interconnect resources
including biomass, hydro and geothermal are known to retire by the end of 2045.

Figure 10.3: Cumulative Resource Retirement Forecast

New Resource Additions
In order to meet future load growth, considering state-defined clean energy goals and
replacement of retired generation, a new generation forecast must include enough
resources to meet peak load. Furthermore, some states include emission constraints or
require emission pricing for new resource additions. Avista uses a resource adequacy-
based forecast for new resource additions along with data estimates provided by a third-
party consultant. The process begins with a forecast of new generation by resource type
from a third-party consultant. Consultants with multiple clients and dedicated staff can,
and more efficiently than Avista, research new resource costs and operating
characteristics on likely resource construction in the West, especially in areas where
Avista has no market presence or local market knowledge. These forecasts for new
generation account for environmental policies and localized cost analysis of resource
choices to develop a practical new resource forecast.

The next step in this process adjusts the clean energy additions to reflect changes in state
policies for additional renewable energy requirements to ensure the new renewable
resource build out matches requirements given the load forecast for each region. The last
step runs the model for 500 simulations to see if each area can meet a resource adequacy
0
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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 186 of 317
Chapter 10: Market Analysis
Avista Corp 2021 Electric IRP 10-8
test. The goal is for each area to serve all load in at least 475 of the 500 iterations, a 95
percent loss-of-load threshold measuring reliability.

Figure 10.4 shows the 230 GW of added generation included in this forecast. The added
resources include 73 GW of utility-scale solar, 43 GW of wind, 13 GW of natural gas
combined cycle CTs, 12 MW of storage3, 23 GW of natural gas CTs and 20 GW of other
resources including hydro, biomass, geothermal and net-metering.

Figure 10.4: Western Generation Resource Additions (Nameplate Capacity)

Generation Operating Characteristics
Several changes are made to the resources available to serve future loads to account for
Avista’s specific expectations such as fuel prices and to reflect potential variation of
resource supply such as wind and hydro generation.

Natural Gas Prices
Historically, natural gas prices were the greatest indicator of electric market price
forecasts. Between 2003 and 2019 the correlation (R2) between natural gas and on-peak
Mid-Columbia electric prices was 0.90, indicating a strong connection between the two
prices. Natural gas-fired generation facilities were typically the marginal resource in the
northwest except for times when hydro generation was high due to water flow. In addition,
natural gas-fired generation met 31 percent of the load in the U.S. Western Interconnect
in 2019. With the large increases in new solar and wind generation in the west, the

3 Storage energy to capacity ratio averages 3 hours in 2022 and increases to 6 hours by 2045. This change
assumes technological advances in the duration of batteries and other storage technologies.
2025 2030 2035 2040 2045
CCCT 3.3 9.9 10.7 11.6 12.8
SCCT 15.4 17.8 19.3 20.2 22.7
DR 2.1 6.0 7.6 9.5 11.5
Storage 7.9 16.2 25.7 35.5 47.1
Net-Meter 4.5 6.5 8.5 10.8 13.9
Solar 25.5 37.5 47.8 59.7 73.0
Wind 7.8 15.7 24.1 33.4 43.3
Geothermal 0.3 0.7 1.2 1.9 2.9
Biomass 0.2 0.4 0.6 0.7 0.9
Hydro 1.3 1.6 1.9 2.4 2.8
-
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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 187 of 317
Chapter 10: Market Analysis
Avista Corp 2021 Electric IRP 10-9
number of hours where natural gas-fired facilities will set the marginal market price is
expected to decline.

For modeling purposes, Avista uses a baseline of monthly natural gas prices and varies
prices based on a distribution for each of the 500 stochastic forecasts. The forecasts
begin with the Henry Hub forecast. Since Avista is not equipped with fundamental
forecasting tools, nor is it able to track natural gas market dynamics across North America
and the world, it uses a blend of market forward prices, consultant forecasts and the
Energy Information Administration (EIA) forecast. The EIA forecast is compared below in
Figure 10.5 against forecasted Henry Hub prices from two consultants with the capability
to follow the fundamental supply and demand changes of the industry. The 24-year
nominal levelized price of natural gas is $4.11 per dekatherm; the 20-year nominal
levelized price is $3.90 per dekatherm4.

Figure 10.5: Henry Hub Natural Gas Price Forecast
Natural gas generation facilities in the West do not use Henry Hub as a fuel source, but
natural gas contracts are priced based on the Henry Hub index. Northwest basins include
Sumas for coastal plants on the Northwest pipe system. Power plants on the GTN pipeline
obtain fuel at prices based on AECO, Stanfield or Malin depending on contracted delivery
rights. Table 10.6 shows these basin differentials as a percent change from Henry Hub.
This table also includes basin nominal levelized prices for both 20 and 24 years for
selected basins.

4 The natural gas pricing data is available on the IRP website as “Natural Gas Prices”.
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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 188 of 317
Chapter 10: Market Analysis
Avista Corp 2021 Electric IRP 10-10
Table 10.6: Natural Gas Price Basin Differentials from Henry Hub

Year Stanfield Malin Sumas AECO Rockies Southern CA
2022 77.7% 84.4% 83.1% 57.8% 81.3% 90.8%
2025 76.2% 81.0% 79.4% 61.1% 82.1% 88.4%
2030 83.6% 87.2% 81.1% 67.5% 87.7% 92.2%
2035 86.4% 89.5% 83.6% 70.1% 91.0% 95.0%
2040 87.8% 90.7% 85.4% 74.1% 93.6% 96.9%
2045 91.2% 93.9% 88.7% 77.5% 96.9% 100.6%
24 yr $3.45 $3.61 $3.43 $2.82 $3.66 $3.86
20 yr $3.23 $3.39 $3.23 $2.63 $3.43 $3.62

As described earlier, natural gas prices are a significant predictor of electric prices. Due
to this significance, the IRP analysis studies prices described on a stochastic basis for
the 500 iterations. The methodology to change prices uses an autocorrelation algorithm
allowing prices to experience excursions, but to not move randomly. The methodology
works by focusing on the monthly change in prices. The forecast’s month-to-month
Expected Case change in prices is used as the mean of a lognormal distribution; then for
the stochastic studies, a monthly change in natural gas price is drawn from the
distribution. The lognormal distribution shape and variability uses historical monthly
volatility. Using the lognormal distribution allows for the large upper price excursions seen
in the historical dataset.

The average of the 500 stochastic prices are similar to the inputted expected price
forecast described earlier in this chapter. Figure 10.6 illustrates the simulated data for the
stochastic studies compared to the input data for the Stanfield price hub. The
stochastically derived nominal levelized price for 20 years is $3.17 per dekatherm
compared to the average price of $3.71 per dekatherm. These values likely would
converge with a sample size much larger than 500. The median price is lower at $2.78
per dekatherm. Another component of the stochastic nature of the forecast is the growth
in variability. In the first year, prices vary 39 percent around the mean, or the standard
deviation as a percent of the mean. By 2040, this value is 58 percent, rising to 60 percent
in 2045. Avista uses higher variation in later years because the accuracy and knowledge
of future natural gas prices becomes less certain.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 189 of 317
Chapter 10: Market Analysis
Avista Corp 2021 Electric IRP 10-11
Figure 10.6: Stochastic Stanfield Natural Gas Price Forecast

Figure 10.7 shows another way to visualize Avista’s natural gas price forecast
assumptions. This chart shows the 24-year nominal levelized prices for Stanfield as a
histogram to demonstrate the skewness of the natural gas price forecast.

Figure 10.7: Stanfield Nominal 20-Year Nominal Levelized Price Distribution

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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 190 of 317
Chapter 10: Market Analysis
Avista Corp 2021 Electric IRP 10-12
Regional Coal Prices
Coal-fired generation facilities are still an important part of the Western Interconnect. In
2019, coal met 18 percent of Western Interconnect loads, falling from 34 percent in 2001.
Coal pricing is typically different from natural gas pricing, providing diversification and
mitigating price volatility risk. Natural gas is delivered by pipeline, whereas coal delivery
is by rail, truck or conveyor. Coal contracts are typically longer term and supplier specific.
Avista uses the coal price forecast contained in Aurora. The software’s forecast is based
on FERC filings for each of the coal plants and used to determine historical pricing. Future
prices are based on the EIA Annual Energy Outlook.

Coal price forecasts have uncertainty like natural gas prices, yet the effect on market
prices is less because coal-fired generation rarely sets marginal prices in the Western
Interconnect. While labor, steel cost and transportation costs drive some portion of coal
price uncertainty, transportation is its primary driver. There is also uncertainty in fuel
suppliers as the coal industry is restructuring. Given the relatively small effect on Western
Interconnect market prices, Avista chose not to model this input stochastically.

Hydro
The Northwest U.S., British Columbia and California have substantial hydro generation
capacity. Hydro resources were 54 percent of Northwest generation in 2019, although
hydro generation is only 22 percent of generation in the Western Interconnect. A favorable
characteristic of hydro power is its ability to provide near-instantaneous generation up to
and potentially beyond its nameplate rating. Hydro generation is valuable for meeting
peak load, following general intra-day load trends, storing and shaping energy for sale
during higher-valued hours and integrating variable generation resources. The key
drawback to hydro generation is its variability and limited fuel supply.

This IRP uses an 80-year study of the hydro data record. The study provides monthly
energy levels for the region over an 80-year hydrological record spanning 1929 to 20085.
Many IRP studies use an average of the hydro record, whereas stochastic studies
randomly draw from the record, as the historical distribution of hydro generation is not
normally distributed. Avista uses both methodologies. Figure 10.8 shows the average
hydro energy as 14,719 aMW (median 14,813 aMW) in the northwest over the 24-year
study, defined here as Washington, Oregon, Idaho and western Montana. The chart also
shows the range in potential energy used in the stochastic study, with a 10th percentile
water year of 11,558 aMW (-22 percent) and a 90th percentile water year of 17,587 aMW
(+19 percent). The EIA reports contain details about hydro generation back to 2001. This
was a historically low hydro year with 11,098 aMW generated, but in 2019, another low
year, 13,041 aMW was generated. Over the 18-year period, not reflected in the 80-year
hydroelectric study, the average was 14,779 aMW, which is in line with the 80-year
average.

Aurora maps each hydro plant to a load zone creating a similar energy shape for all plants
in the load zone. Aurora uses the output from Avista’s proprietary software with a more
accurate representation of the operating characteristics and capabilities of hydro plants.

5 BPA provides the underlying data used for regional hydro data.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 191 of 317
Chapter 10: Market Analysis
Avista Corp 2021 Electric IRP 10-13
Aurora represents hydro plants using annual and monthly capacity factors, minimum and
maximum generation levels, and sustained peaking generation capabilities. The model’s
objective, subject to constraints, shifts hydro generation into peak load hours to maximize
system value consistent with actual plant operations.

Figure 10.8: Northwest Expected Energy
Wind Variation and Pricing
Wind is a growing generation source to meet customer load. As of 2019, 8 percent6 of
Western Interconnect generation was wind, up from nearly zero in 2001. Capturing the
variation of wind generation on an hourly basis is important in fundamental power supply
models due to the volatility of its generation profile and the effect of this volatility on other
generation resources and electric market prices. Energy Exemplar recently made
significant progress populating a larger database of historical wind data points throughout
North America. The IRP leverages this work but takes it one step further by including a
stochastic component to change the wind shape for each year. Avista uses the same
methodology for developing its wind variation as discussed in previous IRPs. The
technique includes an auto correlation algorithm with a focus on hourly generation
changes. It also reflects the seasonal variation of generation.

To keep the problem manageable, Avista developed 15 different annual hourly wind
generation shapes that are randomly drawn for each year of the 24-year forecast. By
capturing volatility this way, the model can properly estimate hours with oversupply
compared with using monthly average generation factors.

6 Wind represented 9.4 percent of Northwest generation in 2019.

0%
50%
100%
150%
200%
250%
300%
11
,
0
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11
,
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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 192 of 317
Chapter 10: Market Analysis
Avista Corp 2021 Electric IRP 10-14
Solar
Like wind, solar is quickly increasing its market share in the Western Interconnect. In 2019
solar was 6 percent7 of the total generation, up from 2 percent in 2014 (both estimates
exclude behind the meter solar). The Aurora model includes multiple solar generation
shapes with multiple configurations, including fixed and single-axis technologies, along
with multiple locations within an area. As solar continues to grow, additional data will
become available and it will be incorporated into future IRP modeling. One of these new
techniques may include multiple hourly solar shapes like those used with wind, so the
model can account for solar variation from cloud cover.

Other Generation Operating Characteristics
Avista uses the Energy Exemplar database assumptions for all other generation types
not detailed here, except for Avista owned and controlled resources. For Avista’s
resources, more detailed confidential information is used to populate the model.

Forced outage and mechanical failure is a common problem for all generation resources.
Typically, the modeling for these events is through de-rating generation. This means the
available output is reduced to reflect the outages. Avista uses this method for solar, wind,
hydro and small thermal plants; but uses a randomized outage technique for larger
thermal plants where the model randomly causes an outage for a plant based on its
historical outage rate, keeping the plant offline for its historical mean time to repair.

Negative Pricing and Oversupply
Avista includes adjustments in the Aurora model to account for oversupply in the Mid-
Columbia market, including negative price effects. Negative pricing occurs when
generation exceeds load. This occurs most often in the Northwest when much of the hydro
system is running at maximum capacity in the spring months due to high runoff and wind
projects are also generating and lacking an economic incentive to shut off due to their
requirement to generate for the Production Tax Credit (PTC), environmental attributes
(e.g., RECs) or sale obligations. Hydro resources are dispatchable, but they may not be
able to dispatch off due to total dissolved gas issues when forced to spill water instead of
generating. This phenomenon will likely increase as wind and solar generation is added
to the system where there are tax credits in place or where environmental attributes are
needed for clean energy requirements. To model this effect in Aurora, Avista changes the
economic dispatch prices for several resources that have dispatch drivers beyond fuel
costs.

The first change Avista made is to the hydro dispatch order. This makes hydro resources
a “must run” resource or last resource to turn off. To do this, hydro generation is assigned
a negative $10 per MWh price (2020 dollars)8. The next change assigns an $8 per MWh
(2020$) reduction in cost for qualifying renewable resources to reflect a preference for
meeting state renewable portfolio standards (RPS); this price adjustment accounts for the

7 Solar represented 0.6 percent of Northwest generation in 2019.
8 These plants cannot be designated with a “must run” designation due to the “must run” resources requiring
resources to dispatch at minimum generation and for modeling purposes, hydro minimum generation is
zero in the event of low flows.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 193 of 317
Chapter 10: Market Analysis
Avista Corp 2021 Electric IRP 10-15
intrinsic value of the REC. The last adjustment is to include a PTC for resources with this
benefit. After these adjustments, the model turns off resources in a fashion similar to
periods of excess generation seen today. In an oversupply condition such as this, the last
resource turned off sets the marginal price.

There could be potential solutions to reduce the amount of negative pricing hours going
forward. One method would reduce the incentive to generate when the power is not
needed. This would mean counting the “spilled” generation toward clean energy
requirements or providing eligibility for tax credits. Other solutions include developing
load-based options to take advantage of low wholesale market prices and increase
requirements. The third method is storage. As storage costs decrease and oversupply
costs increase, storage resources may alleviate oversupply if storage becomes a large
enough resource. For IRP purposes, Avista includes the negative pricing effects so that
load or storage-based options experience the pricing effects in the market for its economic
analysis. Without these adjustments, expected generation from renewable resources may
be overestimated by not including the hours of the year it will be curtailed.

Greenhouse Gas Pricing
Many states and provinces have enacted greenhouse gas emissions reduction programs
with others considering such programs. Some states have emissions trading mechanisms
while others chose clean energy targets. Aurora can model either policy, but different
policy choices can result in dissimilar impacts to electric wholesale pricing. Clean energy
target programs, such as Washington’s CETA, generally depress prices due to the bias
for increasing the incentives to construct low marginal-priced resources. California’s cap
and trade program has the opposite effect and pushes wholesale prices upwards. Avista
includes known programs in California9, British Columbia and Alberta in its modeling as
a carbon tax. The carbon tax approach means the model includes a specified price on
emissions.

Electric Resource and Emissions Forecast
Avista forecasts a major shift to clean energy resources across the Western Interconnect
over the next 24 years. Figure 10.9 shows the historical and forecast generation for the
U.S. portion of the Western Interconnect. In 2019, 42 percent of load is served by clean
energy, increasing to 63 percent by 2030, and 77 percent by 2045. To achieve this shift
in energy, while also serving new loads, solar and wind production will displace coal and
natural gas. Absent significant new storage technologies, thermal resources are required
to help meet system needs during peak weather events, especially in Northwest winters.

9 Pricing used in California uses the low price/high demand scenario from the revised 2019 IEPR carbon
price projects; e.g. $19.20/metric ton in 2022, $33.73/metric ton in 2030, and $67.95/metric ton in 2040.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 194 of 317
Chapter 10: Market Analysis
Avista Corp 2021 Electric IRP 10-16
Figure 10.9: Generation Technology History and Forecast

The northwest will undergo significant changes in future generation. This forecast expects
coal, natural gas and nuclear generation to be limited by 2045; and the remaining
generation requirements will be met with solar, wind and hydro generation. As of 2019,
70 percent of the northwest generation was clean, increasing to 84 percent in 2030 and
91 percent by 2045 as shown in Figure 10.10. Achieving these ambitious clean energy
goals will require a more than doubling of wind generation and a 23-fold increase in solar
energy from the 2019 generation levels. This results in solar providing 12 percent of future
generation and wind 20 percent. Avista expects solar generation will be the renewable
resource of choice in the northwest as quality wind sites are developed and costly
transmission constraints will prohibit new wind in other locations due to the price
competitiveness of solar.

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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 195 of 317
Chapter 10: Market Analysis
Avista Corp 2021 Electric IRP 10-17
Figure 10.10: Northwest Generation Technology History and Forecast

Regional Greenhouse Gas Emissions
Greenhouse gas emissions are likely to significantly decrease with the retirement of coal
generation and solar/wind resources displacing additional natural gas-fired generation.
Avista estimates greenhouse gas emissions for plants within the U.S. Western
Interconnect at approximately 235 million metric tons in 2019, which is close to the 1990
emissions level of 234 million metric tons. Avista obtained historical data back to 1980;
the emissions minimum since 1980 was 161 million metric tons in 1983.

Avista’s market modeling only tracks emissions at their source and does not estimate
assignment to each state from energy transfers, such as emissions generated in Utah for
serving customers in California. Figure 10.11 shows the percent totals for 2019. The
largest emitters by state are Arizona and California, followed by Colorado, Utah and
Wyoming. The four northwest states generate 17 percent of the total emissions in the
Western Interconnect.

Avista expects emissions to decline 20 percent by 2022 compared to 2019 due to coal
plant retirements. By 2045, emissions fall 63 percent compared to 1990 levels as shown
in Figure 10.12. All states will have a reduction in emissions in this forecast except for
modest growth in Idaho. The greatest reductions by percentage are Utah (83 percent),
New Mexico (82 percent), Washington (80 percent), and California (76 percent). The
greatest reductions by tons are California (27 MMT), Utah (24 MMT), Arizona (21 MMT),
and Wyoming (19 MMT).

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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 196 of 317
Chapter 10: Market Analysis
Avista Corp 2021 Electric IRP 10-18
Figure 10.11: 2019 Greenhouse Gas Emissions

Figure 10.12: Greenhouse Gas Emissions Forecast

Regional Greenhouse Gas Emissions Intensity
To understand the greenhouse emissions from Avista’s market purchases, Avista uses
regional emissions intensity per MWh to estimate the associated emissions from these
short-term acquisitions. Avista uses the mean values shown in Figure 10.13 for each of
the 500 simulations. The chart below shows the mean, 25th percentile and 75th percentile
for regional emissions intensity. The emissions are included from Washington, Oregon,
Idaho, Montana, Utah and Wyoming. Emissions intensity falls as renewables are added
41.7
34.5
32.2
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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 197 of 317
Chapter 10: Market Analysis
Avista Corp 2021 Electric IRP 10-19
and coal plants retire, but the intensity rate depends on the variation in hydro production.
The locations for Avista’s potential market purchase radius are consistent with
Washington’s energy and emissions intensity report but is higher than Avista’s likely
counter parties for market purchases.

Figure 10.13: Northwest Regional Greenhouse Gas Emissions Intensity

When evaluating energy efficiency programs in PRiSM a different regional greenhouse
gas emissions intensity is calculated to determine the emission reduction benefits. In this
case, Avista determines the incremental regional emission per MWh. These amounts are
used for determining the avoided societal greenhouse gas emissions using the social cost
of carbon for Washington customers. This is done with two scenarios, the first increases
load and the second decreases load in the Northwest. Loads change by the approximate
amount of energy efficiency Avista may pursue in the future. Avista chose to look at both
load adjustment methods rather than the higher load method due to the higher load
method requiring new generation and this generation may influence the incremental
emissions rate. Conducting both scenarios and averaging the results approximates the
incremental reductions in regional emissions. To estimate the savings, the change in
regional emissions was divided by the change in generation. The results of the two
analyses show the annual incremental emissions intensity in Figure 10.14. The black line
is the fitted curve of the average of the two scenarios and it is used in Avista’s portfolio
modeling for energy efficiency selection. As a comparison, the blue bar is the average
emission rates as shown in Figure 10.13.

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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 198 of 317
Chapter 10: Market Analysis
Avista Corp 2021 Electric IRP 10-20
Figure 10.14: Northwest Incremental Greenhouse Gas Emissions Intensity Rates

Electric Market Price Forecast

Mid-Columbia Price Forecast
Deterministic and stochastic analysis methodologies of the Expected Case are studied
for the IRP. Each study uses hourly time steps between 2022 and 2045 for a simulation
of over 210,000 hours. This process is time consuming when conducted 500 times.
Running the Expected Case 500 times took one week of continuous processing on 33
separate processor cores to complete. Time constraints limit the number of market
scenarios Avista is ultimately able to explore in each IRP.

The annual average of all hourly prices from both studies are shown in Figure 10.15. This
chart shows the annual distribution of the prices using the 10th and 95th percentiles
compared to the mean, median and deterministic prices. The pricing distribution is
lognormal as prices continue to be highly correlated with the lognormally distributed
natural gas prices. The 24-year nominal levelized price of the deterministic study is
$26.05 per MWh and $27.13 per MWh for the stochastic study. See Tables 10.7 and 10.8.
Table 10.8 includes the super peak evening (4 to 10 p.m.) period to illustrate how prices
behave during this high-demand period where solar output is falling, and rising prices
encourage dispatching of other resources.

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Incremental Gen (- Load)Average Rate
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 199 of 317
Chapter 10: Market Analysis
Avista Corp 2021 Electric IRP 10-21
Figure 10.15: Mid-Columbia Electric Price Forecast Range

Table 10.7: Nominal Levelized Flat Mid-Columbia Electric Price Forecast

Metric 2022-2041
Levelized Levelized
Deterministic $24.98 $26.05
Stochastic Mean $25.82 $27.13
10th Percentile $17.54 $18.14
50th Percentile $23.62 $24.84
95th Percentile $42.95 $44.35

Average on-peak prices between 7 a.m. and 10 p.m. on weekdays plus Saturday have
historically been higher than the remaining off-peak prices. However, this forecast shows
off-peak prices outpacing on-peak prices on an annual basis beginning in 2026 due to
increasing quantities of solar generation placed on the system depressing on-peak prices.
As more solar is added to the system, this effect spreads into the shoulder months. Only
in the winter season, where solar production is lowest, does the traditional relationship of
today’s on- and off-peak pricing continue.

Depending on the future level of storage and its duration, price shapes could flatten out
rather than inverting the daytime spread. Mid-day pricing will be low in all months going
forward, driving on-peak prices lower. Super peak evening prices after 4 p.m., when other
resources will need to dispatch to serve load, can be high if startup costs effect market
pricing as expected in this forecast.

$0
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$20
$30
$40
$50
$60
$70
$80
$90
$100
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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 200 of 317
Chapter 10: Market Analysis
Avista Corp 2021 Electric IRP 10-22
Table 10.8: Annual Average Mid-Columbia Electric Prices ($/MWh)

Year Flat Off-Peak On-Peak Super
Peak
2022 $20.37 $18.65 $21.66 $27.31
2023 $18.71 $17.89 $19.34 $23.69
2024 $18.73 $18.32 $19.04 $23.90
2025 $19.99 $19.92 $20.05 $25.07
2026 $23.74 $23.82 $23.68 $29.31
2027 $24.63 $25.12 $24.27 $30.37
2028 $25.67 $26.58 $24.99 $31.97
2029 $26.65 $27.83 $25.77 $33.21
2030 $26.46 $27.78 $25.48 $33.03
2031 $27.63 $29.15 $26.48 $34.44
2032 $28.02 $29.57 $26.86 $35.21
2033 $29.30 $31.08 $27.96 $36.88
2034 $29.42 $31.33 $27.98 $37.26
2035 $30.47 $32.68 $28.81 $39.10
2036 $32.10 $34.41 $30.38 $42.19
2037 $31.95 $34.45 $30.08 $42.57
2038 $34.46 $37.39 $32.26 $46.92
2039 $34.77 $38.04 $32.31 $47.99
2040 $35.67 $39.01 $33.15 $50.67
2041 $38.23 $41.52 $35.77 $56.03
2042 $38.71 $41.79 $36.40 $58.32
2043 $39.27 $42.40 $36.92 $61.88
2044 $46.82 $50.34 $44.18 $73.63
2045 $46.45 $49.28 $44.31 $75.47

Figures 10.16 through 10.19 show the average prices for each hour of the season for
every five years of the price forecast. The spring and summer prices generally stay flat
throughout the 24 years as these periods have large quantities of hydro and solar
generation to stabilize prices, but mid-day prices decrease over time while prices for the
other time periods increase. The winter and autumn prices will have larger price increases
due to less available solar energy to shift unless enough long-term storage materializes.
With this analysis, current on/off-peak pricing will need to change into different products
such as a morning peak, afternoon peak, mid-day and night. Pricing for holidays and
weekends likely will be less impactful on pricing except for the morning and evening
peaks. Future pricing for all resources will need to reflect these pricing curves so they can
be properly valued against other resources.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 201 of 317
Chapter 10: Market Analysis
Avista Corp 2021 Electric IRP 10-23
Figure 10.16: Winter Average Hourly Electric Prices (December - February)

Figure 10.17: Spring Average Hourly Electric Prices (March - June)

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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 202 of 317
Chapter 10: Market Analysis
Avista Corp 2021 Electric IRP 10-24
Figure 10.18: Summer Average Hourly Electric Prices (July - September)

Figure 10.19: Autumn Average Hourly Electric Prices (October - November)

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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Chapter 10: Market Analysis
Avista Corp 2021 Electric IRP 10-25
Scenario Analyses
Electric wholesale market prices will have an impact on this resource plan depending on
how each resource option performs compared to other resources. This comparison uses
market prices along with how each resource performs when customers need them (e.g.,
winter sustained peak). As discussed earlier, market price forecasts can be rather
computer processor and time intensive. However, understanding specific effects on the
marketplace are important to understand the risks involved with resource choice. Avista
studied four additional scenarios beyond the 500 simulations of the Expected Case.
Avista modeled each scenario deterministically. Deterministic studies are sufficient
because the objective of the scenario is to understand the effect of the underlying change
in assumption on the plan. The portfolio sensitivities and market scenarios conducted for
this IRP are discussed below.

Climate Shift Scenario
To understand the effects of increasing future regional temperatures, this study increases
summer loads and decreases winter loads to reflect warming temperatures. This scenario
reflects anticipated climate change impacts to hydro production levels from changes in
streamflow patterns and reduced natural gas plants maximum capabilities in hotter
temperatures.

Avista used data from the Northwest Power and Conservation Council (NPCC) to
estimate the impacts to load and hydro conditions for this market study. For the hydro
changes, Figure 10.20 shows average generation from climate case A, C, and G (orange
line) which is the NPCC’s change scenario compared to their 80-year average northwest
generation quantities. The resulting change is additional hydro generation in the winter
months and less in the spring and summer. Avista assumes climate model results for
2045 in this scenario and linearly interpolates the 80-year average data to the 2045
change from 2021.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 204 of 317
Chapter 10: Market Analysis
Avista Corp 2021 Electric IRP 10-26
Figure 10.20: Change in Hydroelectric Generation

To estimate the climate impacts on load, Avista uses the July 2020 NPCC’s load iteration
climate change scenario to estimate the trending changes in load due to warming
temperatures. In this case, the NPCC took the 2024 operating year load forecast and
estimated how that operating year’s load would perform using predicted temperatures
between 2020 and 2045 from the three different climate change studies A, C and G.
Avista, with assistance from the Pacific Northwest Utility Conference Committee
(PNUCC), created linear changes in load by month given the data provided by the NPCC.
This data is shown in Figure 10.21 and illustrates the monthly impact of warming
temperatures on Northwest loads. Avista used this linear trend to increase or decrease
each monthly load for the Northwest in this scenario.

-
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OCT NOV DEC JAN FEB MAR AP1 AP2 MAY JUN JUL AG1 AG2 SEP
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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Chapter 10: Market Analysis
Avista Corp 2021 Electric IRP 10-27
Figure 10.21: Forecast Change in Monthly Northwest Load Due to Climate Change

Social Cost of Carbon (SCC) Scenario
This scenario shows the implications of a national carbon policy using the SCC as a “tax”
on the entire electric system. In this scenario, power plants are burdened by this cost
when making dispatch decisions. This scenario starts with a lower price of $10 per metric
ton in 2022 escalating to the SCC by year three. By 2030, the price is $112 per metric
ton, $158 in 2040, and $186 in 2045. The levelized price per ton of this scenario is
$108.95 per metric ton. Avista chose to ramp in the SCC pricing to reflect a more probable
climate policy objective then to shock the energy marketplace. Price elasticity effects due
to higher electric prices were not represented in this scenario. This study includes an
updated capacity expansion study to reflect the impacts of the carbon tax on the
economics of thermal generation.

Natural Gas Pricing Scenario
Prevailing low natural gas prices will impact resource selection by lowering electric prices.
This scenario assumes 25th percentile natural gas prices from the Expected Case
stochastic study. The high pricing scenario uses the 95th percentile of the same Expected
Case data set. Both scenarios rely on the Expected Case capacity expansion study.
Figure 10.22 compares the levelized cost of these scenarios to the Expected Case at the
Henry Hub price. The high price scenario is 200 percent above while the low-price
scenario is 35 percent below the Expected Case. This scenario is useful in determining
the viability of future resource options given the change in natural gas prices. For
example, low natural gas price scenarios will make coal and renewable projects less
economic while the high natural gas scenarios will make them relatively more economic.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 206 of 317
Chapter 10: Market Analysis
Avista Corp 2021 Electric IRP 10-28
Figure 10.22: Change in Henry Hub Natural Gas Prices

Scenario Electric Price Results
The results of these studies show a variety of market price impacts from changes in key
assumptions. Figure 10.23 presents the nominal levelized prices for each scenario on a
20- and 24-year basis compared with the Expected Case’s deterministic study. The
deterministic study is shown in the comparison to eliminate other factors for the
comparative analysis. For example, the only change in the study assumptions is the
specific input rather than stochastic assumptions. The annual prices used to estimate the
levelized costs for each scenario is shown in Figure 10.24.

Figure 10.23: Mid-Columbia Nominal Levelized Prices Scenario Analysis

$8.25
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Expected Case(Deterministic)Social Cost ofCarbon Scenario High NG PriceScenario Low NG PriceScenario Climate ShiftScenario
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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Chapter 10: Market Analysis
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The scenario results show with warming temperatures the wholesale prices are lower
over the 24-year period, with 2045 prices 8 percent lower than the Expected Case. The
change in price is due to hydro generation more closely matching higher loads in the
winter; while worse hydro conditions in the summer have only a small effect on summer
prices due to already low hydro generation levels.

The natural gas pricing scenarios show how a 200 percent increase in natural gas prices
causes a 77 percent increase in electric market prices. When natural gas prices are 35
percent lower than the expected case the resulting electric prices are 26 percent lower.

The SCC scenario models the adder as a tax, meaning the marginal price of thermal unit
dispatch increases based upon its carbon content. In this case, prices increase 225
percent compared to the Expected Case or $32 per MWh levelized. This equates to a
$0.30 per MWh impact per $1 of metric ton of greenhouse gas pricing.

Figure 10.24: Mid-Columbia Annual Electric Price Scenario Analysis

Scenario Generation Dispatch Results
Each scenario assumption influences the type of generation dispatched in the Western
Interconnect. Figure 10.25 highlights generation dispatch in each scenario for 2040, and
Table 10.9 shows the percent change in dispatch compared to the Expected Case. The
biggest change in dispatch is in the SCC scenario, where the tax on coal and natural gas
decreases coal-fired generation and increases natural gas and solar generation. Natural
gas dispatch does not significantly change in the natural gas price sensitivities due to the
available resources being the same in each scenario. The major impact of the higher and
lower gas price scenarios is an overall increase or reduction in market prices. In the
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Climate Shift Scenario
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Chapter 10: Market Analysis
Avista Corp 2021 Electric IRP 10-30
climate change scenario, increases to winter hydro production reduces overall coal and
natural gas-fired generation.

Greenhouse gas emissions vary across the scenarios. Figure 10.26 presents the results
for the first and last year of the study, along with the average emissions rate for the 24-
year period. Higher natural gas prices modestly increase emissions in the short term due
to additional coal dispatch, but emissions are slightly less in the long term. Emissions fall
with lower natural gas prices in all years due to less coal dispatch. The climate shift
scenario slightly reduces emissions due to increased hydro generation. The SCC
scenario reduces emissions 20 percent over the course of the study.

Figure 10.25: 2040 Western Interconnect Generation Forecast

Table 10.9: Change in 2040 Regional Generation

Scenario Coal Natural Hydro Nuclear Other Wind Solar
Low NG Price Scenario -5% 2% 0% 0% -1% 0% 0%
High NG Price Scenario 1%-3%0%0%1%0%0%
-1%-2%2%0%0%0%0%
Social Cost of Carbon -54%6%0%0%-7%-1%2%

Expected Case Low NG Price Scenario High NG Price Scenario Climate Shift Scenario Social Cost of CarbonScenario
Solar 22,059 22,040 22,071 22,033 22,550
Wind 17,477 17,461 17,498 17,455 17,367
Natural Gas 14,489 14,782 13,997 14,255 15,309
Coal 4,477 4,251 4,535 4,410 2,069
Nuclear 4,729 4,713 4,740 4,714 4,727
Other 4,605 4,550 4,632 4,585 4,295
Hydro 19,726 19,726 19,726 20,028 19,726
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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 209 of 317
Chapter 10: Market Analysis
Avista Corp 2021 Electric IRP 10-31
Figure 10.26: Scenario Greenhouse Gas Emissions

187 196
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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Avista Corp 2021 Electric IRP 10-32

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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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11. Preferred Resource Strategy
Avista needs to acquire additional reliable sources of power to meet peak planning
requirements for both summer and winter peak loads while also identifying clean
generation resources to meet state and corporate clean energy goals. To achieve these
goals, Avista must maintain system reliability at affordable rates, while meeting the
regulatory and legal obligations of Idaho and Washington, including the new requirements
of Washington State’s Clean Energy Transformation Act (CETA) requiring service of its
state’s retail loads with 100 percent non-emitting resources by 2045. This chapter outlines
a potential path for Avista to meet its future resource needs under these objectives.

Avista generally acquires new resources through a competitive request for proposal
(RFP) process. Avista shortlisted proposals from its 2020 Renewable RFP and is in
contract negotiations to acquire new clean energy and any associated capacity for the
Company’s resource portfolio. Potential additions from the RFP are not included in this
plan since contracts were not completed prior to the required IRP filing date. Any
resources acquired from that RFP will result in changes to the Preferred Resource
Strategy (PRS). While the IRP indicates a resource acquisition plan, it does not include
final pricing, resource availability or account for existing resource opportunities.

The IRP acquisition strategy identified as the PRS uses the best information available at
the time of its analyses, including Avista’s interpretation of CETA requirements. However,
some rules for CETA are still incomplete. The IRP uses a least-cost planning
methodology using specific social costs specified by the law’s planning requirements.
Avista did not assume alternative compliance options in meeting its CETA goals. Final
rules for CETA may change future resource assumptions and plans.

Avista’s PRS describes the lowest reasonable cost portfolio of resources given Avista’s
need for new capacity, energy and clean non carbon emitting resources, while accounting
for social and economic factors prescribed by state policies. This analysis also considers
Section Highlights
• The 2020 Renewable RFP may displace some resources selected in this plan.
• It is economic to exit the Colstrip coal-fired facility; however, an exit strategy
has yet to be agreed upon by all the owners.
• 200 MW of Montana wind is the most economic new resource to meet the CETA
requirements beginning in 2024.
• 211 MW of natural gas CTs are needed for reliability by November 1, 2026 to
offset Colstrip and expiring power contracts. Existing resource options may
allow for a more economic replacement than constructing new facilities.
• Energy efficiency meets 68 percent of customers’ new energy requirements.
• Demand response programs begin in 2024 and provide 71 MW of capacity by
2032.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 212 of 317
energy market risks as alternative portfolios. The analysis tests sensitivities against the
preferred portfolio to measure impacts from critical external factors such as higher and
lower load growth. Portfolio sensitivities are discussed in Chapter 12 – Portfolio
Scenarios.

The resource strategy includes supply-side resources, energy efficiency and demand
response measures. The IRP compares resource options to find the lowest-cost portfolio
to meet capacity deficits in both the winter and summer, annual energy and clean
energy/CETA requirements.

Resource Selection Process
Avista uses three models to evaluate resources in its PRS. Aurora, the first model
discussed in detail in Chapter 10, determines the economic value of each resource option
using its electricity price forecast. For each resource, Aurora defines the following key
pieces of data: resource dispatch, greenhouse gas emissions, operating costs and market
revenue. Aurora also estimates the market value of our contract obligations.

The second model is Avista’s Reliability Assessment Model (ARAM). ARAM first
estimates resource peak credits or the amount of reliable capacity a resource provides to
Avista’s system during the critical peak hours. The second purpose of ARAM is testing
various resource acquisition strategies to ensure when new resources are combined with
the existing portfolio, Avista can meet system planning requirements with a 5 percent loss
of load probability (LOLP). Chapters 6 and 9 discuss this topic in more detail.

A third model, PRiSM (Preferred Resource Strategy Model), aids resource selection using
information from the Aurora and ARAM models. PRiSM evaluates each resource option’s
capital recovery and fixed operation costs relative to their operating margins and
capability to serve energy, peak loads and clean energy obligations. PRiSM then
determines the lowest-cost mix of resources meeting Avista’s resource needs (see
Chapter 6). The model can also measure and optimize the risk of various portfolio
additions when informed by Monte Carlo data. For the PRS, Avista includes its forecast
of 500 Monte Carlo market futures to inform PRiSM. PRiSM is publicly available on
Avista’s IRP website. No known model, either commercially available or at Avista, can
combine hourly or sub-hourly economic dispatch, resource selection and reliability results
into one streamlined model. To ensure Avista’s portfolio is optimal for customers absent
a more granular model, Avista uses an iterative process where the resource selections of
one PRiSM optimization are re-evaluated in the Aurora and ARAM models to determine
the impacts of the PRiSM run on value (Aurora) and system reliability (ARAM).

PRiSM
Avista staff developed the first version of PRiSM in 2002 to support resource decision making in the 2003 IRP. The model continues to support the IRP as enhancements
improved the model over time. PRiSM uses a mixed integer programming routine to
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 213 of 317
support complex decision making with multiple objectives. Its results ensure optimal values for variables given system constraints. The model uses an add-in function to Excel
from Lindo Systems named What’s Best along with the Gurobi solver. Excel then
becomes PRiSM’s user interface. PRiSM simultaneously solves to meet system reliability
obligations and clean energy standards in Washington while minimizing costs. The 2021 IRP PRiSM model analyzes resource need for the entire Avista system and by
state to ensure each state will be assigned the appropriate incremental costs (if any) of
new resource choices. PRiSM includes state-level load and resource balances, and
resources must be added to satisfy deficits for both the system and for each state1. The model can also retire existing resources when they become uneconomic2. Avista employs
these modeling changes to better understand the impacts of Washington State policies
effect on Idaho. These changes also make it easier to account for social costs included
for Washington but are not applicable to Idaho.
The model solves using the net present value of resource costs given the following inputs:

1. Expected future deficiencies for each state and the system
 Summer Planning Margin from ARAM (16 percent, October through April)
 Winter Planning Margin from ARAM (7 percent, May through September)
 Annual energy
 Clean energy requirements
2. Costs to serve future retail loads as if served by the wholesale marketplace (from
Aurora)
3. Existing resource and energy efficiency contributions
 Operating margins
 Fixed operating costs
 Capital Costs
 Greenhouse gas (GHG) emission levels
 Upstream GHG emission levels
 Operating GHG emissions
4. Supply-side resource, energy efficiency and demand response options
 Fixed operating costs
 Return on capital
 Interest expense
 Taxes
 Power Purchase Agreements
 Peak Contribution from ARAM
 Generation levels
 GHG emission levels
 Upstream GHG emission levels
 Construction and operating GHG emissions
 Transmission costs
1 State level constraints are included in the PRiSM model after 2026.
2 Resources can only be retired at the system level. PRiSM cannot “retire” a resource from serving only
one state and transferring the output to the other state.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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5. Constraints
 Must meet energy, capacity and clean energy shortfalls without market
reliance for each state
 Resource quantities available to meet future deficits
The model’s operation is characterized by the following objective function:
Minimize: (WA “Societal” NPV2022-45) + (ID NPV2022-45)
Where:
 WA NPV2022-45 = Market Value of Load + Existing & Future Resource Cost/Operating Margin + Social Cost of Carbon + Energy
Efficiency Total Resource Cost

 ID NPV2022-45 = Market Value of Load + Existing & Future Resource
Cost/Operating Margin + Energy Efficiency Utility Resource Cost Subject to:
 Generation availability and timing
 Energy efficiency potential
 Demand response potential
 Winter peak requirements
 Summer peak requirements
 Annual energy requirements
 Clean energy goals
 T&D constraints

The Preferred Resource Strategy
To meet future customer load and emission reduction requirements, Avista plans to
acquire energy efficiency, participate in demand response programs, make upgrades to its existing thermal and hydro generation fleet, contract for new renewable energy, and
add electricity storage. Avista might acquire resources other than those identified as
preferred due to lower costs or the actual capabilities of resources found when acquiring
new resources through an RFP or similar competitive process. As discussed earlier, this
strategy will also be affected by any new contracted resource resulting from the Company’s 2020 Renewables RFP.

Avista’s resource strategy relies on available information at the time of the IRP analysis,
and may change based on how Avista’s customers use energy in the future, changes in
projected resource costs, development of new technology and the influences of market price conditions on analysis and future acquisition. The strategy uses Avista’s interpretation of CETA requirements since CETA rules were not final when this IRP was
written. Therefore, Avista’s portfolio may change depending on the final CETA
requirements. None of these potential changes due to CETA are expected to alter the
short-term resource decisions being made prior to the development of the 2023 IRP. Resource selections consider economics and environmental objectives while maintaining
customer reliability. Avista’s first major resource adequacy shortfall is expected to occur
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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in 2026, but it may occur earlier if a resource exits the portfolio prior to that date or loads
grow faster than forecasted.

Avista’s interpretation of CETA allows for the financially compensated transfer of clean energy attributes from Idaho to Washington customers. Avista limits these transfers in earlier years of the plan to ensure compliance with renewable energy targets. A complete
description of these assumptions is provided in Chapter 7 – Long-Term Position.

The PRS is separated between the first decade (2022-2031), second decade (2032-2041) and after 2041. The next several sections of this chapter detail the expected resource acquisitions summarizing demand response and energy efficiency projections separately.

2022-2031 Supply-Side Resource Selections
Avista must acquire new energy and capacity resources to meet clean energy goals and
capacity deficits. Table 11.1 shows a complete list of new generation selections and
exiting resources for the 2022 to 2031 period. The first planned resource change is an
economically driven exit of Colstrip. Avista, like other Washington utilities with an
ownership share in Colstrip, is unable to recover costs of coal-fired generation in
Washington rates after 2025. While the fate of the plant will depend on a joint decision
between all owners based on their own economic circumstances, Avista’s most economic
decision based on modeling in this IRP would be exiting both Units 3 and 4 as soon as
possible. Additional scenario analysis on Colstrip is presented in Chapter 12 – Portfolio
Scenarios, showing an exit prior to 2025 modestly benefitting both Idaho and Washington
customers compared with later dates. Given the difficulty of exiting ownership of this
facility, Avista cannot commit to a specific exit or retirement date at this time, but Avista
continues to work toward the optimal exit from the resource.

Avista’s first new resource additions include 200 MW of wind from Montana in 2023 and
2024. The PRS includes wind due to it generating during higher-priced hours compared
to solar, and the potential for Montana wind projects to provide generation during winter
peak load conditions. Another 100 MW of Montana wind is added in 2028.

Avista is investigating the possibility of increasing the capacity of its Kettle Falls biomass
plant by up to 12 MW before 2026. The 35-year old plant is reaching a point where major
equipment replacements are required and repowering at a higher generation level may
be justified given CETA requirements.

In the 2020 IRP, Avista found it to be cost effective to modernize the Post Falls hydro
facility, including increasing the capacity by 8 MW for an energy increase of 4 aMW. Avista
included this upgrade as an assumed upgrade in the plan, meaning the PRiSM model
includes this resource as a fixed resource.

With the exit of Colstrip and the expiration of the Lancaster PPA in October 2026, the
PRS adds 211 MW of natural gas-fired CTs. The 2020 IRP assumed the capacity lost
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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from Colstrip and Lancaster could be met with long duration pumped hydro, but the
updated cost and construction schedule information for pumped hydro caused this
resource to not be selected in this IRP. This modeling result is consistent with a scenario
analysis performed in the 2020 IRP showing natural gas CTs would be required if low-
cost long-duration pumped hydro was not available by 2026. Avista will continue to follow
pumped hydro developments for future consideration and developers can respond to any
capacity RFP issued by the Company. The natural gas-fired facility is split between Idaho
and Washington unevenly. Idaho requires 142 MW and Washington only needs 92 MW
for winter peaking capacity. Washington requires less of the natural gas-fired CT due to
its earlier selection of Montana wind. It may be possible to design a new CT with the ability
to co-fire hydrogen or biofuels to meet CETA’s 100 percent clean energy goals by 2045
if the Company cannot acquire an existing facility or alternative clean energy capacity
resource in a future RFP.

Avista anticipates contracting for 75 MW of existing regional hydro capacity to replace its
expiring Mid-Columbia hydro contracts. Existing hydro generation will likely be
competitive given 2031 is within the timing of the 80 percent CETA requirement. Although
hydro capacity should be available, it will be a competitive process with other utilities to
acquire the generation and it will need to be compared against alternative resource
options.

Table 11.1: 2021 Preferred Resource Strategy (2022-2031)

Resource State Time Period Conditions (MW) Winter Peak Capacity Capability (aMW)
Colstrip 3 & 4 WA/ID TBD -222 -222 -206
Montana wind WA 2023 100 33 45
Montana wind WA 2024 100 33 45
Post Falls modernization WA/ID 2026 8 4 4
Kettle Falls modernization WA/ID 2026 12 12 10
Natural gas CT WA/ID 2027 211 234 191
Montana wind WA 2028 100 28 45
Mid-Columbia Hydro Extension WA 2031 75 44 33

2032-2041 Supply-Side Resource Selections
The second decade of the PRS continues to replace existing resource capacity, meet
future load growth and maintain resource adequacy while adding renewable energy to
meet CETA requirements. A complete list of resource additions for this decade is in Table
11.2. The first resource addition for this decade is a 5 MW Rathdrum CT upgrade in 2035.
The Northeast CT is also expected to retire in 2035, if not earlier. The Northeast CT was
constructed in 1978 and Avista forecasts its retirement in 2035 due to the age of the
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 217 of 317
resource and the lack of availability of parts to maintain the equipment. To replace this
lost capacity and meet load growth, a natural gas-fired CT was selected to serve the
capacity needs of both Washington and Idaho customers.

The first 100 MW solar acquisition occurs in 2038, along with 50 MW of on-site lithium-
ion batteries with four hours of storage for both states. Additional load and the expected
retirement of Boulder Park in 2041 drives the addition of 36 MW of new natural gas-fired
reciprocating engines for Idaho and 100 MW of Montana wind for Washington. The
Montana wind replaces expiring wind contracts while contributing toward CETA goals.

Table 11.2: 2021 Preferred Resource Strategy (2032-2041)
Resource State Time
Period Conditions
(MW)
Winter Peak
Capacity
Capability
(aMW)
Rathdrum upgrade WA/ID 2035 5 5 4
Northeast CT WA/ID 2035 -62 -43 0
Natural gas CT WA/ID 2036 87 96 79
Adams-Neilson Solar WA 2037 -19.2 0 -5
Solar w/ storage WA/ID 2038 100 2 26
4-hour storage (lithium-ion) WA/ID 2038 50 7 -2
Rattlesnake Flat WA/ID 2040 -145 -7 -55
Boulder Park WA/ID 2041 -25 -25 -14
Montana wind WA 2041 100 26 45
Natural gas reciprocating engine ID 2041 36 35 33

2042-2045 Supply Side Resource Selections
The IRP typically does not forecast resource additions beyond 20 years but given the
CETA requirement to be 100 percent clean by 2045 Avista extends modeling resources
to 24 years into the future for certain scenario analyses (see Chapter 12). The final four
years of the plan, while relatively uncertain at this time, identifies the replacement of
existing renewable PPAs with both renewable and storage technologies, including lithium-
ion and liquid air energy storage (LAES). Table 11.3 outlines these additions. No major
resources are expected to leave Avista’s portfolio during this time period absent expiring
PPAs.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 218 of 317
Table 11.3: 2021 Preferred Resource Strategy (2042-2045)
Resource State Time
Period Conditions
(MW)
Winter Peak
Capacity
Capability
(aMW)
Palouse Wind WA/ID 2042 -105 -5 -36
Solar w/ storage WA 2042 117 2 31
4-hour storage (lithium-ion) WA 2042 58 9 -2
Solar w/ storage WA 2043 122 2 31
4-hour storage (lithium-ion) WA 2043 61 9 -2
Liquid Air Energy Storage (LAES) WA 2044 12 7 -1
Solar w/ storage WA 2045 149 3 40
4-hour storage (lithium-ion) WA 2045 75 11 -2
Liquid Air Energy Storage (LAES) ID 2045 10 6 -1

499 44 58

Demand Response Selections
Demand Response (DR) resources are integral to Avista’s strategy to meet customer
peak load requirements with non-emitting resources. Avista does not currently offer any
load management programs, although it has piloted programs in the past3. To understand
the potential for new DR programs, Avista contracted with Applied Energy Group (AEG)
to estimate the amount of DR available in our Idaho and Washington service territories.
Chapter 6 – Demand Response provides an overview of DR programs, their potential and
expected costs. The DR estimate includes 16 programs to reduce as much as 169 MW
of winter peak load and 245 MW of summer peak load. Some programs offer reductions
in both winter and summer, while others only in one season or the other. Avista’s primary
needs are for winter peak reduction, and several programs were found cost effective. The
2021 PRS incorporates the first DR programs in 2024, ramping up to include all cost-
effective DR options by 2027. Table 11.4 shows each DR program selected as part of the
PRS. Figure 11.1 illustrates when DR enters the system and how the penetration of DR
programs increase through 2045.

Meeting reliability targets with DR depends on the length of time each program can reduce
loads. Avista assumes a 60 percent on-peak capacity credit for DR. Due to the limited
duration of the DR programs, Avista’s ARAM model demonstrates these programs
achieve 60 percent of the reliability benefits of a natural gas-fired CT. Actual experience
and program design will ultimately determine the amount of reliable capacity contribution
from these resources.

3 Avista does not have any current plans to institute DR programs specifically for low income energy
assistance and has not performed an assessment of low-income DR programs. If the Company elects to perform such an assessment, it would be coordinated through the Energy Assistance Advisory Group or
the Equity Advisory Group.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 219 of 317
Table 11.4: PRS Demand Response Programs
Program Washington Idaho

Figure 11.1: Annual PRS Demand Response Capability

Energy Efficiency Selections
Energy efficiency meets more than two-thirds of all future load growth. This IRP studied
over 7,300 energy efficiency programs and measures. Avista models energy efficiency
programs individually to ensure each program’s capacity and energy contributions are
valued in detail for the system. This method ensures an accurate accounting of peak
savings that is not possible if programs were bucketed or simply compared to a levelized
price of energy. As described in Chapter 3, long-term energy and peak demand forecasts
already include the benefits of energy efficiency. This requires adjusting the load forecast
used in PRiSM to exclude projected energy efficiency additions so specific program
selections can occur. An iterative process with PRiSM ensures maximum cost-effective
energy efficiency quantities are included in the PRS. PRiSM adds both supply- and
demand-side resources to the PRS. Selected energy efficiency is then reinserted into the
model by increasing the amount of load forecast by the selected energy efficiency
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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 220 of 317
program or resource. The process repeats until the amount of energy efficiency selected
and the amount of energy efficiency added to the load forecast is similar4.

Over the course of the plan, 1,005 cumulative gigawatt-hours are saved through energy
efficiency. When considering transmission and distribution losses, loads are 121 aMW
less with these programs. In total, energy efficiency meets 68 percent of load growth
between 2022 and 2045. Figure 11.2 shows total energy and peak hour savings by state
for both winter and summer. Winter peaks are reduced by nearly 118 MW and summer
peaks are reduced by 111 MW. Over the IRP planning horizon, 23 percent of new energy
efficiency comes from Idaho customers and 77 percent from Washington customers.
Washington has more energy efficiency savings than Idaho relative to load because of
the higher avoided costs driven by CETA and other regulations in Washington.

Most energy efficiency savings are from commercial customers (47 percent), followed by
residential customers (37 percent), with the remainder from industrial customers. The
greatest sources of energy efficiency, at nearly 60 percent, are from lighting, space and
water heating measures. Figure 11.3 shows the program type by share of the total
savings.

The amount of energy efficiency identified in the PRS will lead to specific program creation
in Washington and Idaho. The IRP informs the Avista energy efficiency team in
determining cost-effective solutions and potential new programs for business planning,
budgeting and program development.
Figure 11.2: Energy Efficiency Annual Forecast

4 The difference in this IRP is 1 aMW for energy and 1 MW for capacity through 2045.
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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 221 of 317
Figure 11.3: Energy Efficiency Savings Programs

Reliability Analyses
This plan uses a LOLP metric to ensure future system reliability. Due to the large
computational effort associated with completing reliability assessments, not all years are
able to be evaluated for IRPs. Reliability is assessed in 2025, 2030 and 2040 using ARAM
for this IRP. ARAM simulates 1,000 potential scenarios with different loads, wind
estimates, hydro conditions and forced outage rates for each hour of each year studied.
This analysis includes the resources expected to remain in Avista’s portfolio along with
resource selections from PRiSM associated with the PRS.

The resource adequacy objective of the plan is to have a LOLP at or below 5 percent.
This means up to 5 percent of the 1,000 simulations do not meet all load requirements
over the year. The methodology is similar to the concept of experiencing one resource
adequacy issue in 20 years. The LOLP is measured by any event where loads or reserves
are not met in the simulation. Table 11.5 shows reliability metrics for the PRS for 2025,
2030 and 2040. For comparison, a 333 MW CT addition in 2030 is modeled and included
in the table. This scenario is used as the basis for determining the market reliance
requirements to maintain the 5 percent LOLP. This analysis also assumes the ability to
purchase short-term market power but is limited to 330 MW in high-load periods, meaning
temperatures below 2 degrees Fahrenheit or above 83 degrees (daily average)5; all other
periods are limited to 500 MW.

5 Both temperatures are 99th percentile events.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 222 of 317
The PRS in 2030 is slightly above the 5 percent LOLP target, although Avista is not
proposing additional capacity at this time due to its similarity to the natural gas-fired
alternative and having lower values for the other industry benchmark reliability metrics as
shown in Table 11.5. By 2040, the PRS is resource insufficient and will require more
analysis to determine if the peak credits for different resources are appropriate or if
additional planning reserve margin is required at the end of the study period. The other
reliability metrics shown are Loss of Load Hours (LOLH), which is the average duration
of outages and the Loss of Load Expectation (LOLE) which is the number of days with an
outage event divided by the 1,000 simulations. The LOLE measure is similar to the LOLP
but includes a frequency component. Another way of showing this is the “Total Events”
line item, meaning in the 2030s PRS, 148 events occur in 1,000 simulations. These
events occur in only 5.4 percent of the simulations, meaning simulations with reliability
issues can have more than one event per simulation. The final reliability measurement is
Expected Unserved Energy (EUE), this is a measurement of the average quantity of MWh
the system cannot meet.

Table 11.5: Reliability Metrics
Year 2025 (PRS) (PRS) (PRS) (333 MW
LOLP 4.6% 5.4% 8.8% 5.2%
LOLH 1.45 hours 1.74 hours 2.89 hours 1.89 hours
LOLE 0.12 0.14 0.21 0.15
EUE 233 MWh 266 MWh 548 MWh 316 MWh
Total Events 126 148 228 160

Cost and Rate Projections
The IRP rate projection does not include detailed transmission6, distribution,
administrative and O&M cost recovery costs of the hydro system. Avista assumes these
non-generation costs increase by 2 percent per year to approximate an annual average
customer rate estimate. By 2022, there is an expected difference between Idaho and
Washington rates of nearly one cent per kWh, but over the IRP time horizon these
differences increase to two cents. Annual projected rates are shown in Figure 11.4. Rate
impacts are an important consideration when comparing the portfolio alternatives found
in Chapter 12.

6 Unrelated to specific generation acquisition.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 223 of 317
Figure 11.4: Revenue Requirement and Rate Forecast by State

To help understand costs in more context without scenario comparisons, Figure 11.5
shows the annual rate increase by state for each four-year period of the IRP using only
generation-related costs. Over the first four years of the plan, power and new power
acquisition rates increase nearly 5 percent in Idaho and 7 percent in Washington.
Washington’s increases are from renewable energy and DR program acquisitions, with
nearly half of the costs due to existing resource/load power supply cost and market price
increases. Cost increases in Idaho are mostly from existing resource/load power supply
cost increases along with modest DR costs.

In the next four-year period (2025-2029), cost increases are due to increases in the
market price of electricity and new resource acquisitions. Where Washington acquires
part of its needs earlier to meet CETA, resource acquisitions for Idaho are delayed until
actual capacity needs occur in this four-year period. By 2030, resource acquisition is
limited and power costs stabilize. Idaho has a small cost decrease from selling RECs and
clean energy to Washington. As 2040 approaches, new resource acquisitions and lower
REC sales for Idaho lead to cost increases in both states. Overall power-related costs
increase nearly 4 percent per year in Washington and 3 percent in Idaho.

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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 224 of 317
Figure 11.5: Percent Change in Resource Related Rates
Avista conducted an incremental cost analysis for Washington-related CETA costs using
the incremental cost methodology provided by rule. Between 2022 and 2025, Washington
customers are likely to pay $99 million7 more for the CETA clean energy requirement for
this period. Avista estimates CETA spending must exceed $131 million before qualifying
for an exemption from fully meeting clean energy goals. The spending target is calculated
by summing the cumulative 2 percent annual increases of the weather adjusted
Washington revenue requirement over a four-year period. The cost cap provision is
retrospective and will be based on actual cost from the period. Avista estimated the
difference in expected costs and the CETA cap to forecast would be under its cost cap
during the first four-year compliance period.

Although under the cost cap, the average rate increases from these power-supply
acquisitions alone cause rates to increase 3.7 percent per year more than rates would
rise absent the clean energy legislation. In the remaining years through 2044, Washington
rate increases from power generation additions are approximately 3 percent more per
year compared to the baseline analysis. These figures are below the cap due to
generation cost increases being averaged into the overall utility rate. Beyond 2044,
compliance costs, even when blended with non-power supply related costs, are likely to
exceed the CETA cost cap depending on the methodology used to comply with the 100
percent clean energy requirement.

7 Assumes social cost of carbon in the baseline analysis, baseline analysis is Scenario 2- Baseline 1 in
Chapter 12.
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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 225 of 317
Table 11.6: 2022-2024 Cost Cap Analysis (millions $)
2021 2022 2023 2024 2025 Total
Four Year Max Spending 33 33 33 33 133

Environmental Analyses
Avista has a Company-wide goal to serve all customers with clean energy. This goal
includes meeting 100 percent of retail sales with a combination of clean energy and
emission offsets by 2027 and meeting all retail sales with clean energy by 2045. Avista is
committed to meeting this goal, but must balance it with state policies, affordability and
reliability. Affordability is important to Avista’s customers, most of whom have lower than
state-median household income. In addition, Avista customers live in areas subject to
more extreme winter and summer temperatures than those west of the Cascades,
meaning their energy bills are often higher and are a higher portion of their income.

Avista’s PRS meets 78 percent of its 2027 corporate goal, meaning nearly 80 percent of
energy delivered to all customers is from clean resources including hydro, biomass, wind
and solar prior to any additional clean energy or REC market purchases. Figure 11.6
shows annual amounts of clean energy for the system. By 2045, 86 percent of sales are
provided by clean energy if the PRS is implemented. This means Avista will create or
acquire clean energy over the course of the year to equal 86 percent of retail sales. This
estimate includes existing (shown in blue) and new (shown in green) clean energy
resources. Figures 11.7 and 11.8 illustrate dedicated clean energy for Washington and
Idaho. Washington must acquire clean energy and/or RECs equal to retail sales by 2030.
Idaho’s share of clean energy ranges between 37 and 60 percent depending on the
quantity of annual REC sales to Washington but is still expected to acquire up to 38 aMW
of new clean energy over the 24-year IRP horizon.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 226 of 317
Figure 11.6: Annual Clean Energy for the System Sales

Figure 11.7: Annual Clean Energy for Washington Portion of Sales

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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 227 of 317
Figure 11.8: Annual Clean Energy for Idaho Portion of Sales

With the resource changes of this plan, Avista’s greenhouse gas emissions fall below
2019 levels. In 2019, greenhouse gas emissions from our generating fleet were nearly
three million metric tons prior to any adjustments for market transactions or upstream
emissions. This level declines even if Colstrip remains in the portfolio through 2025, as
shown in the dotted line in Figure 11.9. Emission reductions are largely due to reduced
Colstrip dispatch as low natural gas prices and larger quantities of renewables push
wholesale prices lower. If Colstrip is removed from the portfolio, direct emissions fall to
1.5 million metric tons. Comparing 2030 to 2019, direct emissions drop 2.2 million tons or
74 percent (total of the blue and orange bars).

Avista included estimates from upstream emissions in its IRP analyses. The natural gas
estimate includes between 80,000 and 150,000 metric tons per year from upstream
emissions, as shown in the green bars. Net emissions from market transactions are
shown in the light blue bars and are netted with total emissions in the black line. The chart
assumes the transactions use the annual average northwest regional emissions rate. As
shown, Avista is a net seller of energy through 2026, continuing as a net seller in smaller
increments afterward. This net sales position may reduce emissions using this average
annual rate factor.

Avista’s emissions intensity continues to decline over the course of the IRP. Current
emissions intensity rates are nearly 730 lbs per MWh. The rate is expected to fall below
700 if Colstrip remains in the portfolio and drops to nearly 350 lbs per MWh when it exits.
After the Lancaster PPA expires, emissions rates drop to 200 lbs per MWh and continue
declining as more clean energy resources enter the portfolio. These estimates assume
gross dispatched emission levels compared to retail sales.
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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 228 of 317
Figure 11.9: Greenhouse Gas Emissions
Figure 11.10: Total Net Greenhouse Gas Emissions Intensity

Avoided Cost
Avista calculates the avoided, or incremental cost, to serve customers by comparing the
PRS cost to alternative portfolios. Additional avoided cost estimates for specific resource
types are available in Appendix F for Washington PURPA calculations, and energy
efficiency avoided cost details are in Chapter 5 – Energy Efficiency.

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New Resources
Net Market Transactions
Upstream/Construction/Operations
Net Emissions
2019 Generated Emissions
Dispatched Emissions w/ Colstrip Operating to 2025
353 337 338
284 302
205 194 184 175 164 161 157 149 141 168 141 151 139 129 132 138 119 147 123
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Preferred Resource Strategy
PRS w/ Colstrip Operating to 2025
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 229 of 317
New Resource Avoided Costs
Table 11.7 includes the 2021 IRP avoided costs. However, avoided costs change as
Avista’s loads and resources change, as well as with changes in the wholesale power
marketplace. Avoided costs are a best-available estimate at the time of analysis. Specific
project characteristics will likely change the value of a resource. The prices shown in Table 11.7 represent energy and capacity values for different periods and product types,
including renewable energy projects. For example, a new generation project with equal
annual deliveries in all hours has an energy value equal to the flat energy price shown in
Table 11.7. The table also includes traditional on- and off-peak pricing compared to the
flat price. In addition to the energy prices, these theoretical resources receive capacity value for production at the time of system peak. This value begins in 2026, the first year
of forecasted resource deficiency, for resources that can dependably meet winter peak
requirements.

Capacity value is the resulting average cost of capacity each year. Specifically, the calculation compares the least cost portfolio building to meet capacity requirements
against a lower cost portfolio with no capacity requirements. This is done by comparing
the annual costs of Baseline Portfolio 2 to Baseline Portfolio 3 (shown in Chapter 12).
Avista uses these annual cash flow differences to create annualized costs of capacity
beginning in the first year of a major resource deficit. Recognizing cash flows are lumpy by nature, the variability in annual values are levelized and tilted using a 2 percent inflation
rate. The next step divides the costs by added capacity amounts during the winter peak.
This value is the cost of capacity per MW or cost per kW-year. The capacity payment
applies to the capacity contribution of the resource at the time of the winter peak hour.
Transmission costs associated with new resources are included within the capacity cost.
These include the interconnection of the resource to the system and the cost to wheel
power to Avista’s customers.

The resource must generate 100 percent of its capacity rating at the time of system peak to obtain a full capacity payment. For example, solar receives a 2 percent credit based
on Equivalent Load Carrying Capability (ELCC) analysis and would receive 2 percent of
the capacity payment compared with its nameplate capacity. For wind resources, location
determines the capacity credit received. Northwest wind contributes 5 percent of its
operational capacity to meeting Avista winter peaks, while Montana wind contributes 28 to 35 percent. No matter the resource, Avista will need to conduct an ELCC analysis for
any specific project it evaluates to determine its peak credit.

Variable Energy Resources (VER) consume ancillary services because their output
cannot be forecasted with great precision. VER resources seeking avoided cost pricing may receive reduced payments to compensate for ancillary service costs if the resource
is different than proposed in the PRS. The clean energy premium includes the VER cost
as part of the estimated value

The clean energy premium calculation is similar to the capacity credit but estimates the cost to comply with CETA by comparing the PRS to a portfolio without CETA requirements
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 230 of 317
(see the Baseline 2 scenario in Chapter 12). Avista uses annual cash flow differences to
create an annualized cost of clean energy beginning with the first year of clean energy
acquisition with an annual price adjustment of 2 percent per year. This new annual cost is divided by the incremental megawatt hours of generation and the resulting value shows
the amount of extra cost per MWh needed to meet clean energy requirements. This
benefit includes the cost associated with changing to cleaner capacity resources, but also
adding clean energy resources. Clean energy premiums assume no change to renewable
energy tax incentives but will include any tax incentives if they are extended.
Avista believes the best method for estimating avoided costs of new clean energy
resources is through an RFP process. This ensures resources are competing with other
options. Table 11.7 presents avoided costs from IRP analyses and the present mix of
resources in Avista’s portfolio. As Avista acquires new resources, including resources for CETA compliance, avoided costs will likely fall to reflect the lesser need for clean energy
resources.

Table 11.7: New Resource Avoided Costs
Year Energy
Flat On-Peak Off-Peak Premium ($/kW-Yr)
2022 $20.37 $21.66 $18.65 $0.00 $0.00
2023 $18.71 $19.34 $17.89 $13.27 $0.00
2024 $18.73 $19.04 $18.32 $13.54 $0.00
2025 $19.99 $20.05 $19.92 $13.81 $0.00
2026 $23.74 $23.68 $23.82 $14.09 $0.00
2027 $24.63 $24.27 $25.12 $14.37 $115.10
2028 $25.67 $24.99 $26.58 $14.65 $117.40
2029 $26.65 $25.77 $27.83 $14.95 $119.80
2030 $26.46 $25.48 $27.78 $15.25 $122.20
2031 $27.63 $26.48 $29.15 $15.55 $124.60
2032 $28.02 $26.86 $29.57 $15.86 $127.10
2033 $29.30 $27.96 $31.08 $16.18 $129.70
2034 $29.42 $27.98 $31.33 $16.50 $132.20
2035 $30.47 $28.81 $32.68 $16.83 $134.90
2036 $32.10 $30.38 $34.41 $17.17 $137.60
2037 $31.95 $30.08 $34.45 $17.51 $140.30
2038 $34.46 $32.26 $37.39 $17.86 $143.10
2039 $34.77 $32.31 $38.04 $18.22 $146.00
2040 $35.67 $33.15 $39.01 $18.58 $148.90
2041 $38.23 $35.77 $41.52 $18.96 $151.90
2042 $38.71 $36.40 $41.79 $19.34 $154.90
2043 $39.27 $36.92 $42.40 $19.72 $158.00
2044 $46.82 $44.18 $50.34 $20.12 $161.20
2045 $46.45 $44.31 $49.28 $20.52 $164.40
20 yr. Levelized
24 yr. Levelized

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 231 of 317
There are other non-energy impacts (cost or benefits) that are included when determining
the avoided cost of resources. For example, resources with greenhouse gas emissions
have a social cost of carbon implication for Washington customers. The $ per MWh impact
of this cost is shown in Table 11.8 for three example natural gas-fired resource for each
MWh generated. Further information regarding the social cost of carbon used in the
analysis is provided in Chapter 9 along with workbook details included in Appendix I.

Table 11.8: Natural Gas Social Cost of Carbon Impacts ($/MWh)
Year Modern 1x1 CCCT Reciprocating Frame
6,779 btu/kWh 8,382 btu/kWh 9,817 btu/kWh
2022 $30.28 $37.44 $43.85
2023 $31.40 $38.83 $45.47
2024 $32.56 $40.26 $47.15
2025 $34.25 $42.35 $49.60
2026 $35.49 $43.88 $51.39 2027 $36.76 $45.45 $53.23
2028 $38.07 $47.07 $55.13
2029 $39.42 $48.74 $57.09
2030 $40.81 $50.46 $59.10
2031 $42.24 $52.23 $61.17
2032 $43.71 $54.05 $63.31
2033 $45.23 $55.93 $65.50
2034 $46.79 $57.86 $67.76
2035 $48.40 $59.84 $70.09
2036 $50.05 $61.89 $72.48
2037 $52.40 $64.79 $75.88
2038 $54.17 $66.97 $78.44
2039 $55.98 $69.22 $81.07
2040 $57.85 $71.53 $83.78
2041 $59.77 $73.91 $86.56
2042 $61.75 $76.35 $89.42
2043 $63.79 $78.87 $92.37
2044 $65.88 $81.46 $95.40
2045 $68.03 $84.12 $98.52

Avista recognizes there are other benefits and costs associated with new resources such
as economic, health, reliability, resiliency, energy security and others. Each of these
categories may impact customers differently depending on if they are located in a highly
impacted community or are part of a vulnerable population. Avista was unable to address
these costs and benefits for resources for this IRP but plans to engage a consultant to
estimate these values in the next IRP for Washington resource selection. Many of these
benefits or costs will be either borne by customers or people within the local area of the
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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resource location. If Avista uses these benefits within its resource selection, customers
are at risk to pay additional costs for potential benefits of others.

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12. Portfolio Scenario Analysis

The 2021 Preferred Resource Strategy (PRS) is Avista’s 24-year strategy to meet future
loads and replace generation resources. Because the future is often different from the
IRP’s Expected Case forecast, the future resource strategy needs to be flexible enough
to serve customers under a range of plausible outcomes. This IRP identifies permutations
of potential resource strategies due to resource availability and pricing. Resource
decisions may change depending on how customers use electricity, how the economy
changes and how carbon emission policies evolve. This chapter investigates the cost and
risk impacts to the PRS under different futures the utility might face as well as alternative
resource portfolios.

The 2021 PRS is Avista’s preferred resource plan, but plans may change as alternative
pricing and resource availability is determined in future RFPs. Avista’s IRP is a roadmap
of potential resource acquisition strategies using currently known information. For
example, Avista’s resource strategy might change if a resource adequacy program
develops, if electrification becomes policy for Washington State or if the Company
pursues clean energy at a faster rate. This analysis can also test modeling assumptions
regarding the social cost of carbon for energy efficiency, demand response and other
resource acquisitions. Avista uses two methods to understand cost effects. The first is the
Present Value of Revenue Requirement (PVRR) or the discounted cost customers pay to
serve load and the second method is the average energy rates. The rates calculation is
the year’s revenue requirement divided by energy sales.

In addition to alternative portfolio choices, Avista tested the portfolios under alternative
market futures or sensitivities. These sensitivities show how the portfolios perform with a
carbon tax and with higher or lower natural gas prices. Avista also studied how its portfolio
and cost would change if regional temperatures increase leading to changes in hydro
operations and load.
Chapter Highlights
 2021 IRP analysis shows Colstrip’s removal from Avista’s portfolio earlier than
2025 is more economic for the whole system, while retaining the plant through
2025 reduces power supply cost risk.
 A Northwest Resource Adequacy (i.e. reliability) Program lowers system cost
by 0.4 percent or $4.4 million per year.
 Portfolios with higher levels of clean energy reduce risk if a future national
carbon tax is enacted.
 Supplying all customers with clean energy equal to 100 percent of sales and
retiring Avista’s natural gas-fired plants by 2045 increases rates by 20 percent
in Washington and by 28 percent in Idaho compared to the Preferred Resource
Strategy.
 Warming regional temperatures result in higher winter hydro production while
shifting loads from winter to summer. These changes reduce customers’ cost
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Portfolio Scenarios
Avista studied many alternative portfolios to compare cost, risk and emissions to the PRS
for the Expected Case market forecast. The Company also reviewed two portfolios with
fundamental changes to the marketplace requiring a re-optimization of the resource
strategy. The PRS is Portfolio #1 on all tables and charts in this chapter. The remaining
portfolios change assumptions to arrive at a portfolio to meet a specific objective. The
next section outlines each of the portfolio objectives and resource selection. The resource
selections included in the PRS are in Table 12.1.

Table 12.1: Portfolio #1- Preferred Resource Strategy Resource Selection

Resource Type Year State Capability
(MW)
Colstrip 2021 WA/ID (222)
Montana wind 2023 WA 100
Montana wind 2024 WA 100
Lancaster 2026 WA/ID (257)
Kettle Falls Upgrade 2026 WA/ID 12
Post Falls Upgrade 2026 WA/ID 8
Natural Gas Peaker 2027 ID 85
Natural Gas Peaker 2027 WA/ID 126
Montana wind 2028 WA 100
NW Hydro Slice 2031 WA 75
Rathdrum CT Upgrade 2035 WA/ID 5
Northeast 2035 WA/ID (54)
Natural Gas Peaker 2036 WA/ID 87
Solar w/ storage (4 hours) 2038 WA/ID 100
4-hr Storage for Solar 2038 WA/ID 50
Boulder Park 2040 WA/ID (25)
Natural Gas Peaker 2041 ID 36
Montana wind 2041 WA 100
Solar w/ storage (4 hours) 2042-2043 WA 239
4-hr Storage for Solar 2042-2043 WA 119
Liquid Air Storage 2044 WA 12
Liquid Air Storage 2045 ID 10
Solar w/ storage (4 hours) 2045 WA 149
4-hr Storage for Solar 2045 WA 75

Supply-side resource net total (MW) 1,032
Supply-side resource total additions (MW) 1,589
Demand Response 2045 capability (MW) 71
Cumulative energy efficiency (aMW) 121
Cumulative summer peak savings (MW) 111
Cumulative winter peak savings (MW) 116

Portfolio #2: Baseline Portfolio #1
The objective for this scenario is to understand how the utility would plan its portfolio
without the clean energy targets required under CETA while retaining the social cost of
carbon assumption. Absent this change, this portfolio represents a traditional pre-CETA
clean energy target IRP least cost strategy. This portfolio allows Avista to identify the
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incremental cost and develop the 2 percent rate cap analysis used for alternative
compliance within CETA. The specific resource selection for this portfolio is in Table 12.2.
The major differences between this portfolio and the PRS are higher levels of natural gas-
fired turbines and removal of wind and solar projects. An interesting result of this study is
the model selecting additional storage resources including hydrogen and liquid air energy
storage necessary to meet capacity requirements due to the model limitations on
additional generation in the Rathdrum area without an expensive transmission
enhancement. Avista recognizes it should model off-system natural gas-fired turbines to
compare against building new transmission or non-natural gas-fired resources elsewhere
in the system. Absent this analysis, the financial results from a present value perspective
are not likely to vary significantly.

Overall, this scenario reduces levelized system cost by 1.9 percent versus the PRS,
although 2045 tail risk increases by 69 percent, meaning a significantly riskier portfolio
for cost volatility and potential for higher cost outcomes. By 2045, the Washington energy
rate would be 3.3 percent lower and Idaho’s rate would be 0.7 percent lower than the
PRS. Idaho’s expected rate increases are higher than Washington’s in this portfolio due
to the elimination of REC sales to Washington customers.

Table 12.2: Portfolio #2- Baseline Portfolio #1 Resource Selection

Resource Type Year State Capability
Colstrip 2021 WA/ID (222)
Lancaster 2026 WA/ID (257)
Post Falls Upgrade 2026 WA/ID 8
Natural Gas Peaker 2027 WA 144
Liquid Air Storage 2034 WA 10
Northeast 2035 WA/ID (54)
Liquid Air Storage 2039 WA 14
Boulder Park 2040 WA/ID (25)
Liquid Air Storage 2042-2045 WA 44
Natural Gas Peaker 2027 ID 97
Hydrogen Turbine with 40 Hrs Storage 2041 ID 50
4hr Lithium-Ion 2045 ID 20
Kettle Falls Upgrade 2025 WA/ID 5
Rathdrum Upgrade 2026 WA/ID 12
NW Hydro Slice 2031 WA/ID 75
Natural Gas Peaker 2031 WA/ID 48
Natural Gas Peaker 2036 WA/ID 84

Supply-side resource net total (MW) 53
Supply-side resource total additions (MW) 611
Demand Response 2045 capability (MW) 123
Cumulative energy efficiency (aMW) 123
Cumulative summer peak savings (MW) 111
Cumulative winter peak savings (MW) 121

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Portfolio #3: Baseline Portfolio #2
This portfolio estimates Avista’s premiums for both clean energy and capacity for the
avoided cost calculations. It uses the same assumption as the Baseline #1 portfolio but
also removes the social cost of carbon. This is the least cost strategy given system
constraints. The results are similar to the Baseline Portfolio #1 with slight reductions in
DR and a slight increase in natural gas-fired CTs. This scenario, like the Baseline Portfolio
#1 scenario, reaches the Rathdrum area transmission constraint. Energy efficiency
acquisition and resource removal assumptions remain unchanged in this scenario from
the PRS to keep the load forecast constant to measure cost changes in resource
acquisition. The full resource selection for this portfolio is in Table 12.3.

This scenario reduces levelized system cost by 1.9 percent versus the PRS although the
2045 tail risk increases by 69 percent. By 2045, the Washington energy rate would be 3.1
percent lower and Idaho’s rate would be 0.9 percent lower than the PRS. Idaho rate
increases in this portfolio are higher due to the elimination of REC sales to Washington
customers.

Table 12.3: Portfolio #3- Baseline Portfolio #2 Resource Selection

Resource Type Year State Capability
Colstrip 2021 WA/ID (222)
Kettle Falls Upgrade 2025 WA/ID 5
Lancaster 2026 WA/ID (257)
Rathdrum Upgrade 2026 WA/ID 12
Post Falls Upgrade 2026 WA/ID 8
Natural Gas Peaker 2027 ID 97
Natural Gas Peaker 2027 WA 147
NW Hydro Slice 2031 WA/ID 75
Natural Gas Peaker 2031 WA/ID 48
Liquid Air Storage 2034 WA 10
Northeast 2035 WA/ID (54)
Natural Gas Peaker 2036 WA/ID 84
Liquid Air Storage 2039 ID 10
Liquid Air Storage 2039 WA 14
Liquid Air Storage 2042-2045 WA 44
Hydrogen Turbine w\ 40 Hrs Storage 2041 ID 50
Boulder Park 2040 WA/ID (25)
4hr Lithium-Ion 2045 ID 23

Supply-side resource net total (MW) 68
Supply-side resource total additions (MW) 626
Demand Response 2045 capability (MW) 117

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Portfolio #4: Baseline Portfolio #3
This scenario is not a reliable plan to serve customers, but it is used to compare costs of
other portfolios to determine the change in capacity avoided costs. The social cost of
carbon, clean energy requirements as well as capacity and energy requirements are
removed. Both energy efficiency and resource removals are with the same as the PRS.
This allows the model to only select cost-effective supply-side resources based on energy
benefits. The Company can estimate the avoided cost of capacity and the avoided cost
of clean energy by comparing other baseline portfolios to this baseline. The full resource
selection for this portfolio is in Table 12.4.

While this portfolio is not a reliable plan to meet future load, this scenario reduces
levelized system cost by 5.4 percent and increases tail risk by 84 percent. The
Washington energy rate would be 8.9 percent lower and Idaho’s rate would be 7.3 percent
lower by 2045 under this strategy.

Table 12.4: Portfolio #4- Baseline Portfolio #3 Resource Selection

Resource Type Year State Capability
Colstrip 2021 WA/ID (222)
Post Falls Upgrade 2026 WA/ID 8
Lancaster 2026 WA/ID (257)
Northeast 2035 WA/ID (54)
Boulder Park 2040 WA/ID (25)

Supply-side resource net total (MW) (550)
Supply-side resource total additions (MW) 8
Demand Response 2045 capability (MW) 4

Portfolio #5: Clean Resource Plan (2027)
Avista created a corporate goal of transitioning to 100 percent net clean energy by 2027
and 100 percent clean energy by 2045 subject to the availability of technology and
affordability for Avista’s customers. This portfolio assists the Company with understanding
the resource needs and the costs to meet the 2027 corporate goal. The strategy shows
a need of an additional 500 MW of wind and solar by 2027 to achieve the system-wide
clean energy goal. With these additional resources, natural gas-fired acquisitions fall by
55 MW. The full resource selection for this portfolio is in Table 12.5.

This scenario increases levelized system cost by 3.5 percent versus the PRS and the
2045 tail risk decreases by 33 percent. The Washington energy rate would be 1.7 percent
higher and Idaho’s rate would be 9.0 percent higher than the PRS by 2045; both of these
increases are due to additional renewable acquisition specifically for Washington where
it would no longer be able to access lower cost Idaho RECs and Idaho would pay more
to add wind and solar to meet its 100 percent requirement while also losing the financial
benefits of REC sales to Washington.

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Table 12.5: Portfolio #5- Clean Resource Plan (2027) Resource Selection

Resource Type Year State Capability
Colstrip 2021 WA/ID (222)
Montana Wind 2023 ID 194
Montana Wind 2023 WA 100
Montana Wind 2025 WA 100
Solar Photovoltaic 2026-2027 ID 200
Lancaster 2026 WA/ID (257)
Kettle Falls Upgrade 2026 WA/ID 12
Post Falls Upgrade 20206 WA/ID 8
Natural Gas Peaker 2027 ID 111
Montana Wind 2027 WA 200
Natural Gas Peaker 2027 WA 48
NW Hydro Slice 2031 WA 75
Solar w/ storage (4 hours) 2031 WA/ID 100
4-hr Storage for Solar 2031 WA/ID 50
Rathdrum Upgrade 2035 WA/ID 5
Northeast 2035 WA/ID (54)
Natural Gas Peaker 2036 WA/ID 84
Solar w/ storage (4 hours) 2038 WA/ID 100
4-hr Storage for Solar 2038 WA/ID 50
Boulder Park 2040 WA/ID (25)
Solar w/ storage (4 hours) 2041-2043 WA/ID 349
4-hr Storage for Solar 2041-2043 WA/ID 175
Geothermal 2041 WA/ID 20
Natural Gas Peaker 2043 ID 36
Liquid Air Storage 2044-2045 WA 24
Solar Photovoltaic 2045 WA 26

Supply-side resource net total (MW) 1,509
Supply-side resource total additions (MW) 2,018
Demand Response 2045 capability (MW) 71
Cumulative energy efficiency (aMW) 135
Cumulative summer peak savings (MW) 133
Cumulative winter peak savings (MW) 128

Portfolio #6: Clean Resource Plan (2045)
This portfolio builds on Portfolio #5, but also requires the exiting of all fossil fuel thermal
plants by 2044 with no new natural gas facilities being added. The model assumes
Colstrip can exit at any time based on economics and ignoring the ownership
requirements. This resulted in one unit shutting down and the other remaining online
throughout the study due to the limited capacity options available to replace it. The result
illustrates an interesting conclusion about the plant for Idaho indicating it is economic to
maintain the plant if only expensive options are available to replace it.

The resulting portfolio selection is over 1,149 MW of solar and 500 MW of attached
storage along with an additional 200 MW of wind above the 2027 goal scenario. To meet
capacity needs, 307 MW of hydrogen turbines and 332 MW of storage replace the lost
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natural gas-fired peaking capacity. The full resource selection for this portfolio is in Table
12.6.

This ambitious scenario relies on a liquid energy market which comes at a cost. The
levelized system cost increases 5.1 percent compared to the PRS and the 2045 tail risk
reduces by 68 percent. The Washington energy rate would be 20.3 percent higher and
Idaho’s rate would be 28.2 percent higher than the PRS by 2045.

Portfolio #6b: Clean Resource Plan (2045) without Colstrip
While Portfolio #6 allows fossil fueled thermal plants to exit when economic, this scenario
removes Colstrip while keeping everything else constant. This scenario shows the cost
and resource changes necessary to drive the utility to zero carbon resources by 2045.
This single change increases the amount of renewable resources by approximately 50
MW and increases storage by approximately 30 MW. The full list of resource changes is
shown in Table 12.7. The costs are similar to Portfolio #6, where total cost changes are
also 5.1 percent although 2045 tail risk is 67 percent lower.

Portfolio #7: Social Cost of Carbon for Idaho
CETA requires a social cost of carbon for energy efficiency and fossil fuel resource
selection in Washington. The TAC requested this portfolio to examine the impacts of this
same requirement on Idaho load. The resulting portfolio reduces natural gas acquisition
from 335 MW in the PRS to 280 MW. Energy efficiency increases in Idaho from 27 aMW
to 44 aMW, leading to an additional 13 MW of winter peak load reduction. The full
resource selection for this portfolio is in Table 12.8.

This change in the planning process increases levelized system cost 0.4 percent above
the PRS and reduces the 2045 tail risk by 4.5 percent. The Washington energy rate
increases 0.8 percent and Idaho’s rate is 5.7 percent higher than the PRS portfolio. This
change to the Idaho customer portfolio also leads to a small potential change in resource
acquisition for Washington customers.

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Table 12.6: Portfolio #6- Clean Resource Plan (2045) Resource Selection

Resource Type Year State Capability
Colstrip (Unit 4) 2021 WA/ID (111)
NW Wind On System 2023 ID 100
Montana Wind 2023 WA 100
NW Wind On System 2023 WA/ID 100
Montana Wind 2025 ID 100
Lancaster 2026 WA/ID (257)
Montana Wind 2026 WA/ID 100
Post Falls Upgrade 2026 WA/ID 8
Geothermal 2027 ID 20
Montana Wind 2027 WA 100
Liquid Air Storage 2027 WA 56
Kettle Falls Upgrade 2027 WA/ID 12
Solar w/ storage (4 hours) 2027 WA/ID 115
4-hr Storage for Solar 2027 WA/ID 58
Liquid Air Storage 2029-31 WA 27
NW Hydro Slice 2031 WA/ID 75
Solar w/ storage (4 hours) 2031 WA/ID 111
4-hr Storage for Solar 2031 WA/ID 55
Liquid Air Storage 2033 WA 13
Northeast 2035 WA/ID (54)
Hydrogen Turbine with 40 Hrs Storage 2036 ID 50
Hydrogen Turbine with 40 Hrs Storage 2036 WA 75
Solar w/ storage (4 hours) 2038 WA/ID 100
4-hr Storage for Solar 2038 WA/ID 50
Boulder Park 2040 WA/ID (25)
Liquid Air Storage 2041-2043 ID 20
Solar w/ storage (4 hours) 2040-2043 WA/ID 423
4-hr Storage for Solar 2040-2043 WA/ID 212
Liquid Air Storage 2041 WA 10
Colstrip (Unit 3) 2044 WA/ID (111)
Coyote Springs 2 2044 WA/ID (302)
Kettle Falls CT 2044 WA/ID (9)
Rathdrum 2044 WA/ID (153)
Solar w/ storage (4 hours) 2044 ID 100
4-hr Storage for Solar 2044 ID 50
Hydrogen Turbine with 40 Hrs Storage 2045 ID 182
Liquid Air Storage 2044-2045 WA 206
Solar Photovoltaic 2045 ID 150
Cabinet Gorge Upgrade 2045 ID 68
NW Wind On System 2045 WA 200
Small Nuclear (share) 2045 WA 71
Wood Biomass 2045 WA 25
Solar w/ storage (4 hours) 2045 WA/ID 150
4-hr Storage for Solar 2045 WA/ID 75

Supply-side resource net total (MW) 2,346
Supply-side resource total additions (MW) 3,367
Demand Response 2045 capability (MW) 124
Cumulative energy efficiency (aMW) 140
Cumulative summer peak savings (MW) 138
Cumulative winter peak savings (MW) 136
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Table 12.7: Portfolio #6b- Clean Resource Plan (2045) Resource Selection without
Colstrip
Resource Type Year State Capability
Colstrip (Unit 4) 2021 WA/ID (222)
Montana Wind 2023 ID 100
NW Wind On System 2023 WA 192
Montana Wind 2025 ID 100
Post Falls Upgrade 2026 WA/ID 8
Lancaster 2026 WA/ID (257)
Montana Wind 2026 WA/ID 100
Geothermal 2027 ID 20
Montana Wind 2027 WA 100
Liquid Air Storage 2027 WA 83
Kettle Falls Upgrade 2027 WA/ID 12
Solar w/ storage (4 hours) 2027 WA/ID 128
4-hr Storage for Solar 2027 WA/ID 64
Liquid Air Storage 2029 WA 12
NW Hydro Slice 2031 WA 75
Solar w/ storage (4 hours) 2031 WA/ID 112
4-hr Storage for Solar 2031 WA/ID 56
Pumped Hydro 2031 ID 27
Liquid Air Storage 2033 WA 13
Northeast 2035 WA/ID (54)
Hydrogen Gas Turbine with 40 Hrs Storage 2036 ID 50
Hydrogen Gas Turbine with 40 Hrs Storage 2036 WA 75
Solar w/ storage (4 hours) 2038 WA/ID 100
4-hr Storage for Solar 2038 WA/ID 50
Boulder Park 2040 WA/ID (25)
Solar w/ storage (4 hours) 2040 WA/ID 100
4-hr Storage for Solar 2040 WA/ID 50
Solar w/ storage (4 hours) 2041 ID 120
4-hr Storage for Solar 2041 ID 60
Liquid Air Storage 2041 WA 23
Solar w/ storage (4 hours) 2042-43 WA/ID 231
4-hr Storage for Solar 2042-43 WA/ID 115
Coyote Springs 2 2044 WA/ID (302)
Kettle Falls CT 2044 WA/ID (9)
Rathdrum 2044 WA/ID (153)
Liquid Air Storage 2044 ID 13
Liquid Air Storage 2044-2045 WA 210
Hydrogen Gas Turbine with 40 Hrs Storage 2045 ID 195
Solar Photovoltaic 2045 ID 150
Cabinet Gorge Upgrade 2045 WA/ID 68
NW Wind On System 2045 WA 322
Wood Biomass 2045 WA 39
Solar w/ storage (4 hours) 2045 WA/ID 150
4-hr Storage for Solar 2045 WA/ID 75

Supply-side resource net total (MW) 2,377
Supply-side resource total additions (MW) 3,398
Demand Response 2045 capability (MW) 100
Cumulative energy efficiency (aMW) 139
Cumulative summer peak savings (MW) 128
Cumulative winter peak savings (MW) 129
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Table 12.8: Portfolio #7- Idaho Social Cost of Carbon Portfolio Resource Selection

Resource Type Year State Capability
Colstrip 2021 WA/ID (222)
Lancaster 2026 WA/ID (257)
Post Falls Upgrade 2026 WA/ID 8
Natural Gas Peaker 2027 ID 57
Montana Wind 2027 WA 100
Natural Gas Peaker 2027 WA/ID 88
Kettle Falls Upgrade 2027 WA/ID 12
Rathdrum Upgrade 2029 WA/ID 5
NW Hydro Slice 2031 WA/ID 75
Natural Gas Peaker 2031 WA/ID 48
Liquid Air Storage 2034 WA 10
Northeast 2035 WA/ID (54)
Natural Gas Peaker 2036 WA/ID 87
Solar w/ storage (4 hours) 2038 WA 107
4-hr Storage for Solar 2038 WA 54
Boulder Park 2040 WA/ID (25)
Hydrogen Turbine with 40 Hrs Storage 2041 ID 50
Montana Wind 2041 WA 100
Liquid Air Storage 2044 WA 12
Liquid Air Storage 2045 ID 10
Solar w/ storage (4 hours) 2045 WA 149
4-hr Storage for Solar 2045 WA 74
Montana Wind 2023-2024 WA 200
Solar w/ storage (4 hours) 2042-2043 WA 239
4-hr Storage for Solar 2042-2043 WA 120

Supply-side resource net total (MW) 1,048
Supply-side resource total additions (MW) 1,602
Demand Response 2045 capability (MW) 75
Cumulative energy efficiency (aMW) 139
Cumulative summer peak savings (MW) 135
Cumulative winter peak savings (MW) 131

Portfolio #8: Low Load Forecast
Chapter 3 outlines Avista’s forecast for future expected and alternative load growth. This
portfolio studies negative 0.11 percent load growth. The negative load growth scenario
still requires significant new resources, specifically 248 MW of natural gas-fired
generation over the planning period which is a reduction of 87 MW from the PRS. Wind
selection remains the same, but solar and storage are significantly less than the PRS.
The full resource selection for this portfolio is in Table 12.9. For this scenario, energy
efficiency selection remains constant since Avista has not conducted a conservation
potential assessment for a low load forecast scenario. The intent of this scenario is to
understand changes in resource selections if a low load growth future materializes.

Lower loads should reduce cost, but not necessarily rates. The levelized system cost
decreases by 1.3 percent compared to the PRS and the 2045 tail risk increases 18.8
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percent. The 2045 Washington energy rate increases 7.4 percent and Idaho’s rate is 6.8
percent higher than the PRS portfolio. Rates increase with less energy consumption to
spread costs across compared to the higher load levels in the PRS. It is possible non-
modeled costs would change in the future negating some or all of these rate effects.

Table 12.9: Portfolio #8 Low Load Forecast Resource Selection

Resource Type Year State Capability
Colstrip 2021 WA/ID -222
Montana Wind 2023 WA 100
Lancaster 2026 WA/ID -257
Montana Wind 2026 WA 100
Post Falls Upgrade 2026 WA/ID 8
Natural Gas Peaker 2027 ID 98
Natural Gas Peaker 2027 WA 48
Kettle Falls Upgrade 2027 WA/ID 12
Solar Photovoltaic 2029 WA 28
NW Hydro Slice 2031 WA 75
Rathdrum Upgrade 2031 WA/ID 5
Northeast 2035 WA/ID -54
Natural Gas Peaker 2036 WA/ID 65
Solar w/ storage (4 hours) 2038 WA/ID 104
4-hr Storage for Solar 2038 WA/ID 52
Boulder Park 2040 WA/ID -25
Montana Wind 2041-2042 WA 200
Natural Gas Peaker 2041 ID 36
Solar Photovoltaic 2045 WA 102

Supply-side resource net total (MW) 476
Supply-side resource total additions (MW) 1,034
Demand Response 2045 capability (MW) 56

Portfolio #9: High Load Forecast
As with the low load forecast scenario, the high load growth scenario assumptions are
discussed in Chapter 3. Loads in this scenario grow at 0.73 percent compared to the 0.31
percent growth rate assumed in the PRS. Additional load growth requires minor natural
gas-fired resource additions due to transmission limitations described in earlier scenarios.
Although an additional 114 MW of wind and 192 MW of other capacity resources, such
as hydrogen CTs and storage, are required. The full resource selection for this portfolio
is in Table 12.10. The energy efficiency selection is the same as the PRS for this scenario
since Avista has not conducted a CPA for a higher load scenario.

Higher loads increase cost, but not necessarily rates. The levelized system cost increases
by 1.9 percent compared to the PRS and the 2045 tail risk decreases 19 percent.
Washington’s 2045 energy rate decreases 5.2 percent and Idaho’s rate is 7.1 percent
lower than in the PRS portfolio. Rates decrease in this scenario with the costs being
spread out over higher retail sales than the PRS. Non-modeled costs may change in the
future negating these rate effects.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Table 12.10: Portfolio #9 High Load Forecast Resource Selection

Resource Type Year State Capability
Colstrip 3 2021 WA/ID (111)
Colstrip 4 2022 WA/ID (111)
Lancaster 2026 WA/ID (257)
Natural Gas Peaker 2026 ID 55
Geothermal 2026 WA 20
Post Falls Upgrade 2026 WA/ID 8
Natural Gas Peaker 2027 ID 84
Natural Gas Peaker 2027 WA 92
Kettle Falls Upgrade 2027 WA/ID 12
Rathdrum Upgrade 2027 WA/ID 5
Montana Wind 2028 WA 100
Natural Gas Peaker 2031 ID 55
NW Hydro Slice 2031 WA 75
Rathdrum Upgrade 2035 WA/ID 4
Northeast 2035 WA/ID (54)
Natural Gas Peaker 2036 WA/ID 84
Montana Wind 2038 WA 100
Boulder Park 2040 WA/ID (25)
Hydrogen Gas Turbine with 40 Hrs 2041 ID 50

Portfolio #10: Resource Adequacy (RA) Program
The northwest is investigating a regional program to require a specified planning
methodology including planning margins for load and resource balancing, and to take
advantage of regional load and resource diversity. Specific changes for this scenario
include movement to a 12 percent planning margin for winter and summer peak loads
and specified peak credits for each resource technology. An annual summary of the
changes to the load and resource position are in Figure 12.1. For most years, Avista sees
reductions in capacity requirements except for modest summer additions in the first four
years. The reduction in capacity requirements leads to 50 MW fewer natural gas turbines
and more solar generation. Solar increases due to higher peak credits in a regional RA
program. The RA program assigns solar a 19.2 percent peak credit in the winter and
Avista assumes this benefit is only 2 percent without the RA program. The initial solar
capacity credit assumption may be adjusted in the final program design as additional solar
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is added to the system, which would change the results of this scenario. The full resource
selection for this portfolio is in Table 12.11. The actual peak credits and planning margin
of the program are subject to change if the program moves forward.

The RA program should improve regional resource reliability and ultimately reduce costs
for Avista customers because of lower planning reserve requirements. The results of this
study show levelized system cost decreases 1.9 percent compared to the PRS and the
2045 tail risk increases 13.9 percent due to greater market dependence. The Washington
energy rate increases 0.6 percent by 2045 and Idaho’s rate is 0.7 percent lower than in
the PRS portfolio. The mismatch in rate change effects is likely due to Idaho’s greater
benefit from reduced capacity needs compared to Washington‘s large amount of
renewable requirements. Overall, Washington benefits by $40 million PVRR, but in the
year 2045, timing of resource acquisition shows a minor increase in rates.

Figure 12.1: Resource Adequacy Load Resource Position Changes

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Table 12.11: Portfolio #10: Resource Adequacy Program Resource Selection

Resource Type Year State Capability
Colstrip 2021 WA/ID -222
Solar Photovoltaic 2023 WA 108
Montana Wind 2023 WA 100
Lancaster 2026 WA/ID -257
Kettle Falls Upgrade 2026 WA/ID 12
Post Falls Upgrade 2026 WA/ID 8
Natural Gas Peaker 2027 ID 91
Solar w/ storage (2 hours) 2027 WA 101
2-hr Storage for Solar 2027 WA 25
Natural Gas Peaker 2027 WA/ID 88
Solar Photovoltaic 2028 WA 100
NW Hydro Slice 2031 WA 75
Northeast 2035 WA/ID -54
Rathdrum Upgrade 2035 WA/ID 5
Natural Gas Peaker 2036 ID 56
Natural Gas Peaker 2036 WA 49
Boulder Park 2037 WA/ID -25
Solar w/ storage (4 hours) 2038 WA 137
4-hr Storage for Solar 2038 WA 69
Montana Wind 2041-2042 WA 200
Solar w/ storage (4 hours) 2043 WA/ID 100
4-hr Storage for Solar 2043 WA/ID 50
4hr Lithium-Ion 2045 ID 49
Solar Photovoltaic 2045 WA 106

Supply-side resource net total (MW) 972
Supply-side resource total additions (MW) 1,530
Demand Response 2045 capability (MW) 54
Cumulative energy efficiency (aMW) 123
Cumulative summer peak savings (MW) 123
Cumulative winter peak savings (MW) 116

Portfolio #11: Electrification Portfolio #1 (Existing Technology)
Avista uses three scenarios to identify impacts to the power system if space and water
heating is electrified in the Washington service area. This scenario is a larger effort than
typically studied in an IRP, but it is included to begin the discussion and considerations
of this potential future. First, the results of this study do not include the cost to
homeowners to convert equipment. Second, this analysis does not consider the
significant transmission or distribution grid impacts due to added load as this analysis
only focuses on the resource impacts1 of the additional load. Third, Avista has not re-
studied the northwest electric market to account for pricing and resource availability
impacts. Given the large scope and impacts of this future scenario this issue may be best
suited for a non-IRP analysis on a regional level.
Given this study focuses on the additional resources to meet this added load from
electrification, the current natural gas load forecast was addressed. To estimate the

1 This analysis includes the transmission interconnect costs discussed in Chapter 8 for resource integration.
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added electric load, Avista converted the natural gas load forecast to electric load by
using the relationship shown in Figure 12.2. This load conversion assumes currently
available technology including a mixture of centralized heat pumps and to a lesser extent
ductless heat pumps for space heating, and heat pump water heaters and conventional
technologies for water heating. In warmer temperatures, fewer kWhs are required due to
the efficiency of the heat pump technology. In colder temperatures, the centralized heat
pump technology provides no efficiency benefit over resistance heating at Avista’s typical
winter peak temperature of less than 5 degrees Fahrenheit.

The conversion from natural gas to electric load assumes a 50 percent reduction in natural
gas load by 2030 and an 80 percent reduction by 2045. Of the converted natural gas load,
Avista assumes 75 percent of these conversions will be on the Avista electric system,
while the remaining conversions will be in other electric providers’ service territories within
Avista’s gas-only service territory. The added load is estimated to be 893 MW to the winter
peak hour by 2045, but only 409 MW by 2030 to the same winter peak hour. Energy
needs increase from 89 aMW in 2030 to 197 aMW by 2045. See Figure 12.3. The
challenge with natural gas conversions is the timing of the load which is predominantly in
the winter and is very temperature sensitive. Figure 12.4 illustrates the timing of the load
for 2030, showing both peak and energy increases with 50 percent2 of Washington
customers converting to electric.

Figure 12.2: Natural Gas to Electric Load Relationship

2 Seventy-five percent of those customers are represented here on the Avista electric system.
y = -6E-07x4 + 0.0004x3- 0.036x2 - 0.5641x + 249.89
R² = 0.978
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Figure 12.3: Electrification Scenario #1 Additional Load

Figure 12.4: Electrification Scenario #1 Monthly Load

Avista selected resources to meet this added load for both capacity and energy
requirements including clean energy. This scenario does not assume a match between
delivery of clean energy and the load at the same time. Table 12.12 indicates only a
modest increase in natural gas generation capacity and meets most of the new load with
nearly 500 MW of hydrogen-fired turbines and nearly 1,000 MW of additional wind and
solar resources. These results also include more energy efficiency from additional
customer opportunities that were previously natural gas customers. As mentioned earlier,
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Avista has not updated the electric market simulation for this study and the cost for this
study will not include the full cost of running hydrogen turbines at greater capacity factors
then assumed in the Expected Case. The estimated marginal fuel cost for hydrogen in
2040 is $155 per MWh assuming hydrogen is $3.00 per kilogram. Therefore, if the
hydrogen plant was required to operate in 22 percent of the hours (the load factor of the
new load), the cost increases by $150 million for the hydrogen gas or an additional two
cents per kWh to Washington customers. Currently the modeling only shows the
hydrogen CT running less than 1 percent of the hours due to the availability of lower cost
natural gas market options. It is unknown if Avista would be able to procure the amount
of clean hydrogen necessary without either a massive storage or delivery system. Without
this needed infrastructure, these turbines would need to run on natural gas to serve load.

The limited financial results of this study show the levelized system cost increasing by
10.7 percent over the PRS with the 2045 tail risk decreasing by 12 percent due to greater
amounts of clean energy required. Since this market analysis was not updated, this risk
and cost measurement is unreliable and may be underestimated. By 2045, the
Washington energy rate increases 8.3 percent not including all the other infrastructure
costs or potential hydrogen operation costs, and Idaho’s rate also increases by 3.5
percent due to resource selection timing and the PVRR is only 0.05 percent higher.

It should be noted that the economics of these electrification scenarios do not include the
significant costs related to the stranding of natural gas assets (i.e. the undepreciated,
unrecovered capital investment costs relative to natural gas transmission and
distribution). In addition, determining who might bear that cost. The electric rate payers,
the natural gas rate payers, shareholders or some combination would need to be
determined between several regulatory commissions and Avista.

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Table 12.12: Portfolio #11- Electrification Portfolio #1 Resource Selection

Resource Type Year State Capability
Colstrip 2021 WA/ID (222)
Montana Wind 2023-2024 WA 200
Liquid Air Storage 2025-2028 WA 130
Rathdrum Upgrade 2025 WA/ID 5
Lancaster 2026 WA/ID (257)
Montana Wind 2026 WA 100
Kettle Falls Upgrade 2026 WA/ID 12
Post Falls Upgrade 2026 WA/ID 8
Natural Gas Peaker 2027 ID 91
Natural Gas Peaker 2027 WA 200
Montana Wind 2028 WA 100
Natural Gas Peaker 2029 WA/ID 84
Liquid Air Storage 2030-2035 WA 190
NW Hydro Slice 2031 WA 75
Northeast 2035 WA/ID (54)
Geothermal 2035 WA 20
Hydrogen Turbine with 40 Hrs Storage 2036-2037 WA 153
Hydrogen Turbine with 40 Hrs Storage 2036 ID 50
Liquid Air Storage 2038-2039 WA 59
NW On System Wind 2038 WA 114
Solar w/ storage (4 hours) 2039 WA 127
4-hr Storage for Solar 2039 WA 63
Hydrogen Turbine with 40 Hrs Storage 2040-2043 WA 244
Boulder Park 2040 WA/ID (25)
Hydrogen Turbine with 40 Hrs Storage 2041 ID 50
Solar w/ storage (4 hours) 2041 WA 150
4-hr Storage for Solar 2041 WA 75
NW On System Wind 2042-2043 WA 241
Liquid Air Storage 2044-2045 WA 107
4hr Lithium-Ion 2045 ID 26
NW On System Wind 2045 WA 139

Supply-side resource net total (MW) 2,256
Supply-side resource total additions (MW) 2,813
Demand Response 2045 capability (MW) 68
Cumulative energy efficiency (aMW) 148
Cumulative summer peak savings (MW) 144
Cumulative winter peak savings (MW) 158

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Avista Corp 2021 Electric IRP 12-19
Portfolio #12: Electrification Scenario #2 (Hybrid Natural Gas/Electric System)
To overcome some of the winter peak challenges with the previous scenario, this scenario
lessens the financial impact of electrification by using homeowner natural gas heat only
during colder temperatures. This scenario uses the same assumptions regarding the
number of customers converting to electric but changes the relationship of kilowatt-hours
to dekatherms to account for less additional electric load on the system in colder
temperatures. The relationship used in this scenario is shown in Figure 12.5. This
scenario assumes most customers retain their natural gas furnace but add an electric
heat pump and heat pump water heaters. In this scenario, peak loads reduce 208 MW in
2030 and 442 MW in 2045 from Electrification Scenario #1. Winter peak loads are still
201 MW higher in 2030 and 451 MW higher in 2045 compared to the PRS. Given these
load increases, additional generation will be needed for both the peak requirements, and
147 aMW of additional energy will be needed by 2045.

Figure 12.5: Hybrid Scenario Natural Gas to Electric Load Relationship

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Figure 12.6: Electrification Scenario #2 Load Change from Electrification Scenario
#1

As expected, the cost to meet this additional load is 5.7 percent higher than the PRS.
Although using natural gas during cold temperatures costs 4.5 percent less than a full
conversion to electric (not including T&D costs). Rates are also modestly higher in 2045
compared to the PRS with a 1.4 percent increase in Washington and a 1.6 percent
increase in Idaho. It is worth noting while the energy rate in Idaho is slightly higher, the
PVRR is 0.15 percent lower with the small rate increase due to resource timing and
selection changes.

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Table 12.13: Portfolio #12- Electrification Scenario #2 Resource Selection

Resource Type Year State Capability
Colstrip 2021 WA/ID (222)
Montana Wind 2023-2024 WA 200
Rathdrum Upgrade 2025 WA/ID 5
Lancaster 2026 WA/ID (257)
Montana Wind 2026 WA 100
Kettle Falls Upgrade 2026 WA/ID 12
Post Falls Upgrade 2026 WA/ID 8
Natural Gas Peaker 2027 ID 95
Natural Gas Peaker 2027 WA 159
Liquid Air Storage 2027 WA 12
Montana Wind 2028 WA 100
Liquid Air Storage 2029-2030 WA 50
NW Hydro Slice 2031 WA 75
Natural Gas Peaker 2031 WA/ID 84
Liquid Air Storage 2034-2035 WA 35
Northeast 2035 WA/ID (54)
Natural Gas Peaker 2036 ID 36
Hydrogen Gas Turbine with 40 Hrs 2036 WA 84
Hydrogen Gas Turbine with 40 Hrs 2041 ID 50

Portfolio #13: Electrification Scenario #3 (High Efficiency)
The previous electrification scenarios provide context for additional load using existing
technology and a hybrid system conversion. This third scenario considers whether electric
heating technology improves enough to minimize the cold weather effects of heating with
electric heat pumps. This scenario uses the same assumptions as the previous two
electrification scenarios except it uses a flatter curve to remove most of the cold
temperature effects on electric heat. In this case, in cold weather periods the relationship
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Avista Corp 2021 Electric IRP 12-22
is 50 less kWh per dekatherm of natural gas as shown in Figure 12.7. This change in
efficiency leads to lower loads, but not to the extent seen in Portfolio #12 as shown in
Figure 12.8. The effects on the electric system will be significant even with more efficient
electric heating technology for colder weather applications.

Figure 12.7: High Efficiency Scenario Natural Gas to Electric Load Relationship

The resources added in this scenario are similar to Portfolio #11, but with lower quantities
due to lower peak load and lower energy needs. Results are shown in Table 12.14. Costs
in this scenario are 9 percent higher than the PRS. Idaho costs remain unchanged, but
the 2045 Idaho rate is 3.2 percent higher due to portfolio resource changes.

The cost to electrify the Washington residential and commercial heating system range
between $0.8 to $1.4 billion PVRR and does not include the required T&D investments
and customer equipment needed and the unknown amount of hydrogen or other storage
alternative needed to meet load during the winter. With these costs, there are savings in
natural gas purchases on the distribution side and lower direct greenhouse gas
emissions. While these studies provide some information on potential impacts of
electrification, additional work needs to be done to answer the issues discussed above.
The IRP is not the best vehicle for this type of analysis due to the quantity of analyses
required to complete the IRP and the information needed from T&D planning and
therefore should be studied separately using information informed by regional IRPs.

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Figure 12.8: Electrification Load Increase Comparison

Portfolio #14: 2x Social Cost of Carbon
CETA requires a social cost of carbon for energy efficiency and fossil fuel resource
selection in Washington using a cost of $82.80 per metric ton in 2022 and rising to
$185.90 per metric ton by 2045. This portfolio examines the impacts of doubling these
prices to better understand changes in portfolio selection and cost to the system. The
resulting portfolio, shown in Table 12.15, slightly reduces the overall natural gas build out
and slightly increases storage and energy efficiency selection. Making this change in the
planning process will change system costs. This scenario stress tests the model to see
how resource decisions change.

The levelized system cost increases 0.1 percent over the PRS and reduces the 2045 tail
risk reduces by 2 percent. By 2045, the Washington energy rate increases 0.5 percent
and Idaho’s rate is 0.1 percent lower than the PRS portfolio. From a state-by-state PVRR
point of view, Washington cost increases by $15 million and Idaho cost increases by less
than $1 million over 24 years.

893
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Table 12.14: Portfolio #13- Electrification Scenario #3 Resource Selection

Resource Type Year State Capability
Colstrip 2021 WA/ID (222)
Montana Wind 2023-2024 WA 200
Liquid Air Storage 2025-2028 WA 76
Rathdrum Upgrade 2025 WA/ID 5
Lancaster 2026 WA/ID (257)
Montana Wind 2026 WA 100
Kettle Falls Upgrade 2026 WA/ID 12
Post Falls Upgrade 2026 WA/ID 8
Natural Gas Peaker 2027 ID 91
Natural Gas Peaker 2027 WA 200
Montana Wind 2028 WA 100
Natural Gas Peaker 2029 WA/ID 84
Liquid Air Storage 2030-2035 WA 156
NW Hydro Slice 2031 WA 75
Northeast 2035 WA/ID (54)
Geothermal 2035 WA 20
Hydrogen Turbine with 40 Hrs Storage 2036 ID 50
Hydrogen Turbine with 40 Hrs Storage 2036 WA 92
Liquid Air Storage 2037-2039 WA 81
NW On System Wind 2038 WA 114
Solar w/ storage (4 hours) 2039 WA 125
4-hr Storage for Solar 2039 WA 62
Boulder Park 2040 WA/ID (25)
Hydrogen Turbine with 40 Hrs Storage 2040-2041 WA 107
Hydrogen Turbine with 40 Hrs Storage 2041 ID 50
Solar w/ storage (4 hours) 2041 WA 150
4-hr Storage for Solar 2041 WA 75
Liquid Air Storage 2042-2045 WA 161
NW On System Wind 2042 WA 145
Solar w/ storage (4 hours) 2043 WA 150
4-hr Storage for Solar 2043 WA 75
4hr Lithium-Ion 2045 ID 26
NW On System Wind 2045 WA 137

Supply-side resource net total (MW) 2,169
Supply-side resource total additions (MW) 2,727
Demand Response 2045 capability (MW) 68
Cumulative energy efficiency (aMW) 141
Cumulative summer peak savings (MW) 121
Cumulative winter peak savings (MW) 154

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Avista Corp 2021 Electric IRP 12-25
Table 12.15: Portfolio #14- 2x Social Cost of Carbon Resource Selection

Resource Type Year State Capability
Colstrip 2021 WA/ID (222)
Montana Wind 2023-2024 WA 200
Lancaster 2026 WA/ID (257)
Kettle Falls Upgrade 2026 WA/ID 12
Post Falls Upgrade 2026 WA/ID 8
Natural Gas Peaker 2027 ID 91
Natural Gas Peaker 2027 WA/ID 110
Montana Wind 2028 WA 100
NW Hydro Slice 2031 WA 75
Rathdrum Upgrade 2033 WA/ID 5
Liquid Air Storage 2034 WA 10
Northeast 2035 WA/ID (54)
Natural Gas Peaker 2036 WA/ID 86
Solar w/ storage (4 hours) 2038 WA/ID 100
4-hr Storage for Solar 2038 WA/ID 50
Boulder Park 2040 WA/ID (25)
Natural Gas Peaker 2041 ID 36
Montana Wind 2041 WA 100
Solar w/ storage (4 hours) 2042-2043 WA 230
4-hr Storage for Solar 2042-2043 WA 115
Liquid Air Storage 2044 WA 13
4hr Lithium-Ion 2045 ID 29
Solar w/ storage (4 hours) 2045 WA 149
4-hr Storage for Solar 2045 WA 75

Supply-side resource net total (MW) 1,035
Supply-side resource total additions (MW) 1,593
Demand Response 2045 capability (MW) 75
Cumulative energy efficiency (aMW) 124
Cumulative summer peak savings (MW) 114
Cumulative winter peak savings (MW) 119

Portfolio #15: Colstrip Exit in 2025
Regardless of Avista’s preference, the Company does not have unilateral control of
Colstrip’s eventual shutdown date due to the structure of the ownership agreement.
Avista’s PRiSM model, used to develop optimized resource strategies, allows the plant to
exit the portfolio in any year to avoid future costs if it is economic to do so. This portfolio,
along with the next two scenarios, is used to understand the cost if the Colstrip units
remain on-line for different lengths of time. In this scenario, the 2025 date is used to
coincide with the CETA requirement to remove coal from rates in Washington State. The
model in this scenario requires the plant to maintain operation through 2025 before exiting
the portfolio.

Since the plant was determined by the model to be economic to exit in 2022, the cost of
this scenario is higher. The levelized system cost increases 0.3 percent over the PRS
and tail risk remains the same since the final resource mix is the same as the PRS. This
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Avista Corp 2021 Electric IRP 12-26
portfolio is shown in Table 12.16. From a PVRR cost perspective, Washington’s cost
increases by $22 million (0.3 percent) and Idaho’s increase by $12 million (0.3 percent)
compared to the PRS.

Table 12.16: Portfolio #15- Colstrip Exit in 2025 Resource Selection

Resource Type Year State Capability
Montana Wind 2023-2024 WA 200
Colstrip 2025 WA/ID (222)
Lancaster 2026 WA/ID (257)
Kettle Falls Upgrade 2026 WA/ID 12
Post Falls Upgrade 2026 WA/ID 8
Natural Gas Peaker 2027 ID 85
Natural Gas Peaker 2027 WA/ID 126
Montana Wind 2028 WA 100
NW Hydro Slice 2031 WA 75
Rathdrum Upgrade 2035 WA/ID 5
Northeast 2035 WA/ID (54)
Natural Gas Peaker 2036 WA/ID 87
Solar w/ storage (4 hours) 2038 WA/ID 100
4-hr Storage for Solar 2038 WA/ID 50
Boulder Park 2040 WA/ID (25)
Natural Gas Peaker 2041 ID 36
Montana Wind 2041 WA 100
Solar w/ storage (4 hours) 2042-2043 WA 239
4-hr Storage for Solar 2042-2043 WA 119
Liquid Air Storage 2044 WA 12
Liquid Air Storage 2045 ID 10
Solar w/ storage (4 hours) 2045 WA 149
4-hr Storage for Solar 2045 WA 75
Montana Wind 2023-2024 WA 200

Supply-side resource net total (MW) 1,032
Supply-side resource total additions (MW) 1,589
Demand Response 2045 capability (MW) 71
Cumulative energy efficiency (aMW) 121
Cumulative summer peak savings (MW) 111
Cumulative winter peak savings (MW) 116

Portfolio #16: Colstrip Exit in 2035
As with Portfolio #15, this scenario requires Colstrip to maintain operation, but increases
the length of operations through 2035, before exiting the portfolio to understand the cost
impacts of an additional 10 years of operating the Idaho share of the plant. This scenario
assumes the former Washington portion of the plant’s cost or benefit is borne by
shareholders and is not included in this study. The cost of this scenario is higher as
expected from the result of the PRS. The resource mix shown in Table 12.17 is slightly
different than the PRS because the Colstrip capacity is replaced at different times. The
levelized system cost increases 0.3 percent above the PRS and tail risk is 1.2 percent
less due to resource selection changes. From a PVRR cost perspective, Washington’s
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Avista Corp 2021 Electric IRP 12-27
cost increase by $31 million (0.4 percent) and Idaho by $15 million (0.3 percent)
compared to the PRS. These results show that the additional 10 years of Colstrip
operation are only expected to increase Idaho’s PVRR by $3 million, but Washington’s
cost increase by $9 million. Even though Washington is not receiving any of the Colstrip
power beyond 2025 due to portfolio resource changes in Idaho, Washington cannot share
resources with Idaho as optimally as in the PRS.

Table 12.17: Portfolio #16- Colstrip Exit in 2035 Resource Selection

Resource Type Year State Capability
Montana Wind 2023-2024 WA 200
Natural Gas Peaker 2026 WA 51
Lancaster 2026 WA/ID (257)
Post Falls Upgrade 2026 WA/ID 8
Natural Gas Peaker 2027 WA/ID 125
Kettle Falls Upgrade 2027 WA/ID 12
Montana Wind 2028 WA 100
Natural Gas Peaker 2031 ID 36
NW Hydro Slice 2031 WA 75
Northeast 2035 WA/ID (54)
Colstrip 2035 WA/ID (222)
Rathdrum Upgrade 2035 WA/ID 5
Natural Gas Peaker 2036 ID 92
Solar w/ storage (4 hours) 2038 WA/ID 100
4-hr Storage for Solar 2038 WA/ID 50
Liquid Air Storage 2039 WA 10
Boulder Park 2040 WA/ID (25)
Natural Gas Peaker 2041 ID 36
Montana Wind 2041 WA 100
Solar w/ storage (4 hours) 2042-2043 WA 239
4-hr Storage for Solar 2042-2043 WA 119
4hr Lithium-Ion 2045 ID 24
Liquid Air Storage 2045 WA 12
Solar w/ storage (4 hours) 2045 WA 149
4-hr Storage for Solar 2045 WA 75

Supply-side resource net total (MW) 1,062
Supply-side resource total additions (MW) 1,620
Demand Response 2045 capability (MW) 64
Cumulative energy efficiency (aMW) 120
Cumulative summer peak savings (MW) 109
Cumulative winter peak savings (MW) 114

Portfolio #17: Colstrip Exit in 2045
This scenario requires Colstrip to maintain operation throughout the entire IRP. This
scenario also assumes the Washington share of the plant’s ongoing operational costs or
benefits are borne by shareholders after 2025. As expected, the cost of this scenario is
higher than the PRS. The resource mix as shown in Table 12.18 reduces the amount of
new natural gas resources due to Colstrip not being replaced. The levelized system cost
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Avista Corp 2021 Electric IRP 12-28
increases by 0.4 percent above the PRS and the 2045 tail risk is 15.4 percent less due to
a less variable generation and fuel supply. From a PVRR cost perspective, Washington’s
cost increases $27 million (0.3 percent) and Idaho’s cost increases by $24 million (0.5
percent) compared to the PRS. These results show the additional 20 years of operation
compared to a 2025 exit increase Idaho’s PVRR by $12 million, but Washington’s cost
increase by $5 million because of other portfolio changes.

Overall, the three Colstrip portfolios show the 76 MW Idaho portion of the Colstrip plant
modestly increases costs with the plant continually operating compared to it exiting the
portfolio. Due to the small change in costs and the unknown future of both the market and
operating cost, it is clear continuing the plant operation or exiting the plant has similar
cost when considering this uncertainty. Avista also recognizes other utilities with
ownership shares may reach different outcomes for the facility depending on whether an
immediate replacement for the resource is needed. For example, if Avista were not
currently long on capacity of similar quantities as the Colstrip plant, it is likely the plant
would be economic to continue operations through 2025.

Portfolio #18: Clean Energy Delivered Each Hour
The compliance method for meeting the CETA goals have yet to be determined regarding
the intent to be 100 percent net clean by 2030 and 100 percent by 2045. The PRS
assumes Avista must acquire clean energy equaling 100 percent of adjusted Washington
retail sales with an allowance for 20 percent unbundled RECs in 2030 and transitioning
to no unbundled RECs by 2045. This means if the Company acquires the clean energy,
it does not need to be delivered to the customer in the same hour or instantaneously. This
scenario attempts to understand the consequences of meeting a 100 percent delivery
requirement. Currently, Avista’s modeling tools are not designed for this scenario. In order
to meet this scenario’s objective, it requires a look at likely generation profiles of both
existing and new resource options in order to see if and how generation can be re-shaped
to meet load profiles.

Avista studied 2030, 2040 and 2045 generation profiles to first see if the resources from
the PRS met the 100 percent clean delivery goal using expected delivery shapes of
renewables. The analysis showed the PRS likely would meet the delivery goal in 2030,
although 81 aMW of its generation is in excess of load and would be unbundled RECs in
an average water year. By 2040, where it is expected the amount of allowed unbundled
RECs should decline to 10 percent the PRS would not meet the delivery requirement in
an average water year due to exceeding the limit of unbundled RECs. To overcome this
constraint Avista would need to add more clean energy resources such as 100 MW of
wind and 150 MW of solar to increase the probability of generation being available at the
hourly time of load.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 261 of 317
Chapter 12: Portfolio Scenario Analysis

Avista Corp 2021 Electric IRP 12-29
Table 12.18: Portfolio #17- Colstrip Exit in 2045 Resource Selection

Resource Type Year State Capability
Montana Wind 2023-2024 WA 200
Lancaster 2026 WA/ID (257)
Post Falls Upgrade 2026 WA/ID 8
Natural Gas Peaker 2027 WA/ID 125
Kettle Falls Upgrade 2027 WA/ID 12
Montana Wind 2028 WA 100
Natural Gas Peaker 2031 ID 36
NW Hydro Slice 2031 WA 75
Northeast 2035 WA/ID (54)
Rathdrum Upgrade 2035 WA/ID 5
Natural Gas Peaker 2036 WA/ID 86
Solar w/ storage (4 hours) 2038 WA/ID 100
4-hr Storage for Solar 2038 WA/ID 50
Boulder Park 2040 WA/ID (25)
Natural Gas Peaker 2041 ID 36
Montana Wind 2041 WA 100
Solar w/ storage (4 hours) 2042-2043 WA 238
4-hr Storage for Solar 2042-2043 WA 119
4hr Lithium-Ion 2045 ID 24
Liquid Air Storage 2044 WA 13
Solar w/ storage (4 hours) 2045 WA 149
4-hr Storage for Solar 2045 WA 75

Supply-side resource net total (MW) 1,216
Supply-side resource total additions (MW) 1,552
Demand Response 2045 capability (MW) 64
Cumulative energy efficiency (aMW) 119
Cumulative summer peak savings (MW) 108
Cumulative winter peak savings (MW) 113

The 2045 goal of 100 percent of delivered clean energy is too difficult to model as it is
unknown what clean resources will be available in the market each hour to serve load
when Avista is short clean energy in addition to the intermittent nature of renewables and
the hydro variability. While it is impractical for the utility to plan to be a clean energy
electrical island, studying these complexities assists in understanding potential storage
and renewable needs for this future. The challenge is to find the additional amount of
storage and renewables to balance load and generation without using market purchases
or thermal resources to meet Washington’s hourly load assuming average hydro
conditions. This scenario is not optimized for cost, but rather optimized to minimize
additional MWh of storage to renewable generation. Beyond the PRS, 300 MW of wind,
400 MW of solar and 100 MW of biomass is required. This results in 240 aMW in excess
generation compared to load and some of the additional renewables would need to be
curtailed or sold assuming Avista was able to procure an additional 500 MW of storage
capability with 27,000 MWh of storage. For context, this level of storage requirement is
nearly equal to the total system load for an entire day. The resource selection in Table
12.19 demonstrates how these requirements could be met with the resource options, but
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Avista Corp 2021 Electric IRP 12-30
Avista would still need to conduct additional hydro variability and market studies to
determine the feasibility of resource selection along with an optimized cost analysis. In
this case, 2045 rates are 19.6 percent higher than the PRS in Washington and 1.5 percent
higher in Idaho. For the 2045 goal, Avista anticipates, absent new low-cost storage
technology, to exceed the CETA cost cap for 2045 obligations due to the cost increases
of storage and additional clean energy requirements under this scenario.

Table 12.19: Portfolio #18- Clean Energy Delivered Each Hour Resource Selection

Resource Type Year State Capability
Colstrip 2021 WA/ID (222)
Montana Wind 2023-2024 WA 200
Lancaster 2026 WA/ID (257)
Kettle Falls Upgrade 2026 WA/ID 12
Post Falls Upgrade 2026 WA/ID 8
Natural Gas Peaker 2027 ID 85
Natural Gas Peaker 2027 WA/ID 126
Montana Wind 2028 WA 100
NW Hydro Slice 2031 WA 75
Northeast 2035 WA/ID (54)
Rathdrum Upgrade 2035 WA/ID 5
Natural Gas Peaker 2036 ID 73
Pumped Hydro Storage 2036 WA 500
NW On System Wind 2038 WA 100
Solar w/ storage (4 hours) 2038 WA 150
4-hr Storage for Solar 2038 WA 75
Solar w/ storage (4 hours) 2038 WA/ID 100
4-hr Storage for Solar 2038 WA/ID 50
Boulder Park 2040 WA/ID (25)
Montana Wind 2041 WA 100
Solar w/ storage (4 hours) 2042-2045 WA 538
4-hr Storage for Solar 2042-2045 WA 269
NW On System Wind 2042 WA 100
NW Off System Wind 2042 WA 100
Solar w/ storage (2 hours) 2042 WA 100
2-hr Storage for Solar 2042 WA 25
Liquid Air Storage 2044 WA 12
Liquid Air Storage 2045 ID 10
Wood Biomass 2045 WA 100

Supply-side resource net total (MW) 2,456
Supply-side resource total additions (MW) 3,014
Demand Response 2045 capability (MW) 71
Cumulative energy efficiency (aMW) 121
Cumulative summer peak savings (MW) 111
Cumulative winter peak savings (MW) 116

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 263 of 317
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Avista Corp 2021 Electric IRP 12-31
Portfolio #19: Social Cost of Carbon Cost on Purchases/Sales
Avista uses a social cost of carbon in its portfolio optimization of energy efficiency and
fossil fuel generation options. Avista did not assign any social cost of carbon for short-
term market purchases or benefits of market sales. This portfolio tests the impact of the
resource strategy adding this cost to the model. In the current modeling process, Avista
is unable to separate purchases and sales and, therefore, uses the net purchases and
sales for this study. For the carbon content of market transactions, the study uses the
annual average emissions rate included in the market price forecast as described in
Chapter 9. Table 12.20 describes the resource selection for this scenario. Compared to
the PRS, the model selection for this scenario is biased toward wind and selects less
solar and storage. This is likely due to the potential carbon content in storage inherent
with using market purchases used to recharge the storage resources.

The levelized system cost increases with this change by 0.3 percent compared to the
PRS and reduces 2045 tail risk by 1.6 percent. By 2045, the Washington energy rate
increases 0.6 percent and Idaho’s rate increase 0.4 percent relative to the PRS portfolio
due to resource selection changes.

Table 12.20: Portfolio #19- SCC on Purchases/Sales Resource Selection

Resource Type Year State Capability
Colstrip 2021 WA/ID (222)
Montana Wind 2023-2024 WA 200
Lancaster 2026 WA/ID (257)
Kettle Falls Upgrade 2026 WA/ID 12
Post Falls Upgrade 2026 WA/ID 8
Natural Gas Peaker 2027 ID 92
Montana Wind 2027 WA 100
Natural Gas Peaker 2027 WA/ID 95
NW Hydro Slice 2031 WA 75
Montana Wind 2031 WA 100
Northeast 2035 WA/ID (54)
Rathdrum Upgrade 2035 WA/ID 5
Natural Gas Peaker 2036 WA/ID 92
Boulder Park 2039 WA/ID (25)
Natural Gas Peaker 2040 WA/ID 63
NW On System Wind 2041 WA 116
Liquid Air Storage 2043-2045 ID 34
Solar w/ storage (4 hours) 2043 WA 120
4-hr Storage for Solar 2043 WA 60
Liquid Air Storage 2044-2045 WA 22
NW On System Wind 2045 WA 100

Supply-side resource net total (MW) 737
Supply-side resource total additions (MW) 1,295
Demand Response 2045 capability (MW) 64
Cumulative energy efficiency (aMW) 123
Cumulative summer peak savings (MW) 111
Cumulative winter peak savings (MW) 121
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 264 of 317
Chapter 12: Portfolio Scenario Analysis

Avista Corp 2021 Electric IRP 12-32
Portfolio #20: Average Market Emissions Intensity Used for Energy Efficiency
This scenario tests the sensitivity of the social cost of carbon to the cost of energy
efficiency. The CETA legislation requires using a social cost of carbon for energy
efficiency acquisition, but it is unclear regarding what emissions rate to assign to energy
efficiency or how it should be derived. From an operational perspective, reducing Avista’s
load with energy efficiency will not likely have any significant impact on the operations of
its fossil fuel generation as these plants dispatch to wholesale market prices which do not
include a social cost of carbon component. Energy efficiency will reduce the need for new
resources with lower loads. Avista indirectly modeled these benefits by requiring energy
efficiency to be co-optimized with supply side resources. The next question is whether
Avista’s operational emissions change with energy efficiency, as less load will likely lead
to less emissions in the marketplace. For the PRS, Avista uses the annual incremental
emissions rate described in Chapter 9 per a request from the WUTC staff. This amount
is higher than the average market emissions rate Avista used in the 2020 IRP. The
purpose of this scenario is to understand the difference in energy efficiency acquisition
between the two methods. It is unclear to Avista if the legislature intended for a utility to
increase its energy efficiency programs for emissions reduction for other utilities in the
region.

Resource selection changes in this scenario due to energy efficiency changes shown in
Table 12.21. Annual energy efficiency savings are 10 aMW less by 2045 or 12 percent
due to this assumption change. Given this change since the last IRP, Avista’s energy
efficiency goals are higher along with making Washington customers’ PVRR $32 million
higher than the PRS due to this change and average customer rates are 0.7 percent
higher than the PRS. Idaho rates are also 0.3 percent higher due to resource selection
changes.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 265 of 317
Chapter 12: Portfolio Scenario Analysis

Avista Corp 2021 Electric IRP 12-33
Table 12.21: Portfolio #20- Average Market Emissions Intensity for Energy
Efficiency Resource Selection

Resource Type Year State Capability
Colstrip 2021 WA/ID -222
Montana Wind 2023-2024 WA 200
Lancaster 2026 WA/ID -257
Kettle Falls Upgrade 2026 WA/ID 12
Post Falls Upgrade 2026 WA/ID 8
Natural Gas Peaker 2027 ID 96
Natural Gas Peaker 2027 WA 84
Montana Wind 2028 WA 100
Natural Gas Peaker 2031 ID 37
NW Hydro Slice 2031 WA 75
Northeast 2035 WA/ID -54
Rathdrum Upgrade 2035 WA/ID 5
Natural Gas Peaker 2036 WA/ID 86
Solar w/ storage (4 hours) 2038 WA/ID 101
4-hr Storage for Solar 2038 WA/ID 50
Boulder Park 2040 WA/ID -25
Natural Gas Peaker 2041 ID 36
Montana Wind 2041 WA 100
Solar w/ storage (4 hours) 2042-2043 WA 239
4-hr Storage for Solar 2042-2043 WA 120
Liquid Air Storage 2044 WA 12
Liquid Air Storage 2045 ID 10
Solar w/ storage (4 hours) 2045 WA 149
4-hr Storage for Solar 2045 WA 75

Supply-side resource net total (MW) 1,038
Supply-side resource total additions (MW) 1,595
Demand Response 2045 capability (MW) 75
Cumulative energy efficiency (aMW) 111
Cumulative summer peak savings (MW) 98
Cumulative winter peak savings (MW) 112

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 266 of 317
Chapter 12: Portfolio Scenario Analysis

Avista Corp 2021 Electric IRP 12-34
Cost and Rate Comparison
Avista chose two different metrics to illustrate the cost differences among the portfolios.
The first metric is total revenue requirement and the second is average customer rates.
This is a simple rate calculation of total revenue requirement divided by retail sales. The
full 24-year term along with intermediate time steps for each of the methodologies is in
Table 12.22. The table shows the results of the portfolios including present value of
revenue requirements (PVRR) and the effective average energy rate for 2030 and 2045
for both states over 24 years.

Table 12.22: Portfolio Costs and Rates

Scenario WA-
PVRR
($ Mill)
PVRR
($ Mill)
2030
Rate
2045
Rate
Rate
($/kWh)
Rate
($/kWh)
1- Preferred Resource Strategy 8,703 4,543 0.127 0.173 0.110 0.153
2- Baseline 1 8,418 4,578 0.121 0.168 0.110 0.152
3- Baseline 2 8,418 4,580 0.121 0.168 0.110 0.151
4- Baseline 3 8,125 4,405 0.117 0.158 0.106 0.141
5- Clean Resource Plan (2027) 8,800 4,910 0.129 0.176 0.121 0.166
6- Clean Resource Plan (2045) 8,965 4,951 0.130 0.209 0.122 0.196
6-b Clean Resource Plan (2045) 9,004 4,918 0.132 0.208 0.120 0.190
7- SCC Idaho 8,732 4,568 0.126 0.175 0.112 0.161
8- Low Load Forecast 8,575 4,492 0.130 0.186 0.113 0.163
9- High Load Forecast 8,916 4,576 0.123 0.164 0.104 0.142
10- RA Program 8,663 4,531 0.126 0.174 0.109 0.152
11- Electrification 1 10,117 4,545 0.131 0.188 0.109 0.158
12- Electrification 2 9,471 4,536 0.127 0.176 0.109 0.155
13- Electrification 3 9,894 4,543 0.128 0.181 0.109 0.158
14- 2x SCC 8,718 4,544 0.127 0.174 0.110 0.152
15- Colstrip Exit 2025 8,725 4,555 0.127 0.173 0.110 0.153
16- Colstrip Exit 2035 8,734 4,558 0.127 0.174 0.108 0.153
17- Colstrip Exit 2045 8,729 4,567 0.127 0.173 0.108 0.154
18- Clean Energy Deliver by Hr. 9,162 4,567 0.127 0.207 0.110 0.155
19- SCC on Net P/S 8,726 4,561 0.126 0.174 0.110 0.153
20- Use Avg Market for EE SCC 8,671 4,543 0.126 0.172 0.108 0.153
21- Max. WA Customer Benefit 10,764 4,569 0.166 0.259 0.110 0.151

The lowest overall cost and the lowest energy rate portfolios are different due to the
inclusion of net energy sales in the rate calculation. Portfolios with less energy sales may
have higher rates due to fewer kWhs over which to spread total costs. Figure 12.9 shows
the energy rates by portfolio sorted from lowest to highest for Washington and Figure
12.10 shows the same information for Idaho. The portfolios are sorted by the lowest 2045
rate on top. The lowest rate portfolios include the baseline scenarios for Washington as
they do not include the clean energy targets. High economic growth also has lower rates
as more energy is available to spread costs over and it is also a lower rate portfolio. The
higher rate portfolios have additional energy requirements. For Idaho, most of the
portfolios have similar rates due to the nature of most of the portfolio scenarios affecting
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 267 of 317
Chapter 12: Portfolio Scenario Analysis

Avista Corp 2021 Electric IRP 12-35
Washington, but for portfolios requiring Idaho to add additional clean energy directly or
indirectly increase cost.

Figure 12.9: Washington Portfolio Average Energy Rates

Avista’s optimization model does not select new resources based on the rate of power,
but rather the PVRR of the total system with societal costs for Washington. The resulting
revenue requirements for each state and the system are shown in Figure 12.11. The data
is sorted by system PVRR in billions of dollars. The Idaho and Washington values shown
illustrates the effects on each state given the changes in the portfolio requirements. The
chart also shows the benefits or costs in relative impacts to each portfolio. It is worth
noting the average rate methodology compared to the PVRR method illustrates the
change in order of portfolio costs; for example, low load growth is one of the lower PVRR
cost but on the higher end of the rate comparison. This is similar when looking at the
electrification scenarios where the added sales dampens the rate impact (absent non-
modeled costs).

0.166
0.130
0.132
0.127
0.131
0.130
0.128
0.129
0.127
0.126
0.126
0.126
0.127
0.127
0.127
0.127
0.127
0.126
0.121
0.121
0.123
0.117
0.259
0.209
0.208
0.207
0.188
0.186
0.181
0.176
0.176
0.175
0.174
0.174
0.174
0.174
0.173
0.173
0.173
0.172
0.168
0.168
0.164
0.158
21- Maximum WA Customer Benefit
6- Clean Resource Plan (2045)
6b- Clean Resource Plan (2045) No…
18- Clean Energy Delivered Each Hr
11- Electrification 1
8- Low Load Forecast
13- Electrification 3
5- Clean Resource Plan (2027)
12- Electrification 2
7- SCC Idaho
10- RA Market
19- SCC on Net P/S
14- 2x SCC
16- Colstrip Exit 2035
17- Colstrip Exit 2045
1- Preferred Resource Strategy
15- Colstrip Exit 2025
20- Use Avg Mrkt for EE SCC
3- Baseline 2
2- Baseline 1
9- High Load Forecast
4- Baseline 3
WA 2045 Rate ($/kWh)
WA 2030 Rate ($/kWh)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 268 of 317
Chapter 12: Portfolio Scenario Analysis

Avista Corp 2021 Electric IRP 12-36
Figure 12.10: Idaho Portfolio Average Energy Rates

0.122
0.120
0.121
0.113
0.112
0.109
0.109
0.109
0.110
0.108
0.110
0.108
0.108
0.110
0.110
0.110
0.110
0.109
0.110
0.110
0.104
0.106
0.196
0.190
0.166
0.163
0.161
0.158
0.158
0.155
0.155
0.154
0.153
0.153
0.153
0.153
0.153
0.152
0.152
0.152
0.151
0.151
0.142
0.141
6- Clean Resource Plan (2045)
6b- Clean Resource Plan (2045) No…
5- Clean Resource Plan (2027)
8- Low Load Forecast
7- SCC Idaho
11- Electrification 1
13- Electrification 3
12- Electrification 2
18- Clean Energy Delivered Each Hr
17- Colstrip Exit 2045
19- SCC on Net P/S
16- Colstrip Exit 2035
20- Use Avg Mrkt for EE SCC
15- Colstrip Exit 2025
1- Preferred Resource Strategy
14- 2x SCC
2- Baseline 1
10- RA Market
21- Maximum WA Customer Benefit
3- Baseline 2
9- High Load Forecast
4- Baseline 3
ID 2045 Rate ($/kWh)
ID 2030 Rate ($/kWh)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 269 of 317
Chapter 12: Portfolio Scenario Analysis

Avista Corp 2021 Electric IRP 12-37
Figure 12.11: Portfolio Average Energy Levelized Revenue Requirement

Greenhouse Gas Analysis
The portfolios studied in the chapter show a net reduction of greenhouse gas emissions.
Emissions are lower due to the exit of Colstrip and the electric marketplace’s large amount
of clean energy driving dispatch of remaining coal and natural gas plants lower. Figure
12.12 shows the differences in greenhouse gas emissions from the alternative portfolios
in 2022 and 2045. This methodology shows Avista’s emissions at the beginning and end
of the IRP. The emissions included in this chart are direct emissions of greenhouse gases.
This methodology clearly displays known emission levels based on forecasts of expected
run hours for thermal resources and excludes impacts of upstream emissions and
estimates market emissions. Most portfolios end with the same emissions range due to
similar levels of natural gas-fired facilities.

4.6
4.5
4.5
4.5
4.9
5.0
4.6
4.9
4.6
4.6
4.6
4.6
4.6
4.6
4.5
4.5
4.5
4.5
4.5
4.6
4.6
4.4
10.8
10.1
9.9
9.5
9.0
9.0
9.2
8.8
8.9
8.7
8.7
8.7
8.7
8.7
8.7
8.7
8.7
8.7
8.6
8.4
8.4
8.1
15.3
14.7
14.4
14.0
13.9
13.9
13.7
13.7
13.5
13.3
13.3
13.3
13.3
13.3
13.3
13.2
13.2
13.2
13.1
13.0
13.0
12.5
21- Maximum WA Customer Benefit
11- Electrification 1
13- Electrification 3
12- Electrification 2
6b- Clean Resource Plan (2045) No Colstrip
6- Clean Resource Plan (2045)
18- Clean Energy Delivered Each Hr
5- Clean Resource Plan (2027)
9- High Load Forecast
7- SCC Idaho
17- Colstrip Exit 2045
16- Colstrip Exit 2035
19- SCC on Net P/S
15- Colstrip Exit 2025
14- 2x SCC
1- Preferred Resource Strategy
20- Use Avg Mrkt for EE SCC
10- RA Market
8- Low Load Forecast
3- Baseline 2
2- Baseline 1
4- Baseline 3
System- PVRR ($ Bill)
WA- PVRR ($ Bill)
ID-PVRR ($ Bill)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 270 of 317
Chapter 12: Portfolio Scenario Analysis

Avista Corp 2021 Electric IRP 12-38
Figure 12.12: Levelized Greenhouse Gas Emissions

Another way to look at emission reductions is to compare the reduction to the PRS and
how the portfolio cost changes. Figure 12.13 is a complex chart showing this effect where
each point is a portfolio showing the relative change in cost and emissions compared to
the PRS (at the center of the chart). In this case, the emissions are the levelized net
emissions with market impacts and cost is the levelized cost of the system. A way to test
whether the PRS stands up against other portfolios in this measurement is to identify if
any portfolios with lower cost and less emissions exist. In this example, Portfolio #20
marginally achieves this criterion. This portfolio uses the average market emission rate
for the energy efficiency calculation. The reason it performs better in this measurement
is that costs are lower due to using fewer high cost energy efficiency measures and
emissions are lower due to slightly higher clean energy purchases.

1.91
1.46
1.46
1.46
1.46
1.46
1.69
1.46
1.91
1.46
1.46
1.91
1.46
1.46
1.46
1.46
1.46
1.46
1.46
1.46
1.68
1.46
0.89
0.57
0.57
0.56
0.56
0.56
0.56
0.54
0.54
0.54
0.54
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0.50
0.50
0.50
0.50
0.48
0.44
0.33
-
-
17- Colstrip Exit 2045
11- Electrification 1
13- Electrification 3
3- Baseline 2
12- Electrification 2
2- Baseline 1
9- High Load Forecast
19- SCC on Net P/S
15- Colstrip Exit 2025
1- Preferred Resource Strategy
20- Use Avg Mrkt for EE SCC
16- Colstrip Exit 2035
14- 2x SCC
10- RA Market
18- Clean Energy Delivered Each Hr
5- Clean Resource Plan (2027)
7- SCC Idaho
8- Low Load Forecast
21- Maximum WA Customer Benefit
4- Baseline 3
6- Clean Resource Plan (2045)
6b- Clean Resource Plan (2045) No Colstrip
2045 Emissions
2022 Emissions
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 271 of 317
Chapter 12: Portfolio Scenario Analysis

Avista Corp 2021 Electric IRP 12-39
Figure 12.13: Change in Greenhouse Gas Emissions Compared to Change in Cost

Risk Analysis
Avista’s 500 simulations of market prices allow Avista to study the portfolio cost in different
market conditions in order to understand the power cost risk of these potential futures.
For this risk analysis Avista looks at standard deviation, which measures variability in
cost, this can be either positive or negative risk. Avista’s measure of tail risk is the
difference between the mean cost of the 500 simulations and the 95th percentile.

Avista typically shows its cost versus risk metrics graphically with cost on the x-axis and
risk on the y-axis to show the tradeoff between cost and risk. The best portfolios are in
the bottom left of the chart with low risk and low cost. In past IRPs, Avista developed an
efficient frontier to show the best cost versus risk portfolios. Given the new complexities
of CETA and splitting each of the portfolio cost between states to show which is driving
the actual cost, Avista did not have time to conduct this analytical comparison. Figure
12.14 shows the 2030 standard deviation of power cost in the y-axis compared to the
levelized revenue requirement of the system in the x- axis. The PRS is in the upper middle
and the remaining portfolios are labeled to show their relative comparison.

The tail risk analysis using the same cost versus risk metric is shown in Figure 12.15.
This method of reviewing risk uses the same x-axis for cost but uses the 2045 Tail95 risk
on the y-axis. These two methods produce similar results although the Tail95
measurement illustrates higher relative risk for the baseline scenarios. Also, since this is
a view of 2045, the differences can illustrate portfolio differences between 2030 and 2045.

2- Baseline 1
3- Baseline 2
4- Baseline 3
5- Clean Resource
Plan (2027)
6- Clean Resource
Plan (2045)
7- SCC Idaho
8- Low Load
Forecast
9- High Load
Forecast
10- RA Market
11- Electrification 112- Electrification 2
13- Electrification 3
14- 2x SCC 15- Colstrip Exit
2025
16- Colstrip Exit
2035
17- Colstrip Exit
2045
18- Clean Energy
Delivered Each
Hour
19- SCC on Net
P/S20- Use Avg Mrkt for EE
SCC
6b- Clean
Resource Plan
(2045) No
Colstrip
21- Maximum WA
Customer Benefit
-$100
-$50
$0
$50
$100
$150
$200
-0.400 -0.300 -0.200 -0.100 0.000 0.100 0.200 0.300 0.400 0.500
Ch
a
n
g
e

i
n

L
e
v
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d

C
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s
t

F
r
o
m

L
R
C
S

(
m
i
l
l
i
o
n
s
)

Change in Levelized GHG Emissions from LRCS (MMT)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 272 of 317
Chapter 12: Portfolio Scenario Analysis

Avista Corp 2021 Electric IRP 12-40
Figure 12.14: Portfolio’s Standard Deviation versus Portfolio’s Levelized PVRR

Figure 12.15: Portfolio’s Tail Risk vs Portfolio’s Levelized PVRR

1- Preferred Resource
Strategy
2- Baseline 1
3- Baseline 2
4- Baseline 3
5- Clean Resource
Plan (2027)
6- Clean Resource
Plan (2045)
7- SCC Idaho
8- Low Load Forecast
9- High Load
Forecast
10- RA Market
11- Electrification 1
12- Electrification 213- Electrification 3
14- 2x SCC
17- Colstrip Exit 2045
18- Clean Energy
Delivered Each Hour
20- Use Avg Mrkt for
EE SCC
21-
Customer Benefit
6b- Clean Resource
Plan (2045) No
Colstrip
$0
$10
$20
$30
$40
$50
$60
$1,000 $1,050 $1,100 $1,150 $1,200 $1,250 $1,300 $1,350
20
3
0

S
t
d
e
v

(
m
i
l
l
i
o
n
s
)
2022-2045 Levelized Revenue Requirement (Millions)
1- Preferred Resource
Strategy
2- Baseline 1
3- Baseline 24- Baseline 3
5- Clean Resource
Plan (2027)
6- Clean Resource
Plan (2045)
7- SCC Idaho
8- Low Load Forecast
9- High Load Forecast
10- RA Market
11- Electrification 1
12- Electrification 2
13- Electrification 3
14- 2x SCC
15- Colstrip Exit 2025
16- Colstrip Exit 2035
17- Colstrip Exit 2045
18- Clean Energy
Delivered Each Hour
19- SCC on Net P/S
20- Use Avg Mrkt for
EE SCC
21-
Customer Benefit
6b- Clean Resource
Plan (2045) No
Colstrip$0
$50
$100
$150
$200
$250
$300
$1,000 $1,050 $1,100 $1,150 $1,200 $1,250 $1,300 $1,350
20
4
5

T
a
i
l

R
i
s
k

(
m
i
l
l
i
o
n
s
)
2022-2045 Levelized Revenue Requirement (Millions)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 273 of 317
Chapter 12: Portfolio Scenario Analysis

Avista Corp 2021 Electric IRP 12-41
Considering total cost with risk, Figure 12.16 shows the lowest cost portfolio with risk
included. In this measurement, the PVRR of the Tail95 risk is added to the PVRR. The
risk component is included in blue and the expected cost is in green. The method shows
the lowest risk adjusted cost is Portfolio #4, although this portfolio does not meet capacity
or clean energy requirements. The next best portfolio meeting all requirements is Portfolio
#17 with Colstrip exiting in 2045 for Idaho and 2025 for Washington. This portfolio has
lower risk than exiting Colstrip early and this lower risk offsets the higher expected cost.
It is worth noting this analysis does not include risk metrics on the future cost of capital or
operations to operate the Colstrip plant through 2045. The other portfolios with direct
comparison to the PRS with lower risk adjusted cost are both extending Colstrip beyond
2022 (#14 & #16) and two of the social cost of carbon assumption changes (#19 & #20).
Given these results, there could be merit in using the average market (or lower) emissions
rate for energy efficiency’s social cost of carbon and potentially using market emissions
for purchases/sales.

Figure 12.16: Portfolio PVRR with Risk Analysis

$0 $2 $4 $6 $8 $10 $12 $14 $16 $18
4- Baseline 3
17- Colstrip Exit 2045
8- Low Load Forecast
16- Colstrip Exit 2035
20- Use Avg Mrkt for EE SCC
15- Colstrip Exit 2025
19- SCC on Net P/S
1- Preferred Resource Strategy
14- 2x SCC
10- RA Market
7- SCC Idaho
2- Baseline 1
3- Baseline 2
5- Clean Resource Plan (2027)
9- High Load Forecast
6- Clean Resource Plan (2045)
6b- Clean Resource Plan (2045) No Colstrip
18- Clean Energy Delivered Each Hour
12- Electrification 2
13- Electrification 3
11- Electrification 1
21- Maximum WA Customer Benefit
PVRR (Bill $)
PV Tail 95 (Bill $)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 274 of 317
Chapter 12: Portfolio Scenario Analysis

Avista Corp 2021 Electric IRP 12-42
Reliability Analysis
Each of the portfolios discussed in this chapter use planning margins to determine the
quantity of new resources required to have a reliable system. In addition to planning
margins, resources are also assigned a peak credit to estimate each resource’s
contribution to meeting the system planning margin. Many of the scenarios change
existing resources and have high amounts of intermittent renewable energy so the peak
credits assumed in this study may not apply when larger quantities of the resource are
deployed or as Avista’s resource mix changes such as any new contracted resources
signed at the conclusion of the 2020 Renewable RFP. While it may be of interest to study
the reliability by year of each of the portfolios studied in this IRP, the time needed to
perform such an analysis would be unachievable in time to release the final IRP. Although
certain portfolios and certain years warrant further study, Avista selected the scenarios
and years shown in Table 12.23 to represent the appropriate areas of focus to determine
the validity of the 16 percent planning margin and the peak credits used in this IRP.

Based on this reliability analysis, high renewable penetrations show either the planning
margin is too low or peak credits are too high to maintain a reliable system. This is
demonstrated by the 2040 analysis of the Portfolio 6 Clean Resource Plan with a 7.5
percent LOLP versus 5.4 percent in the PRS. Analysis shows if Colstrip is retained
through 2030, the LOLP is slightly higher than the PRS is in 2030 without the plant. This
demonstrates the utility will have similar, if not slightly improved, reliability without Colstrip
in the portfolio. The last insight from this study is the RA program analysis. In this case,
lowering the planning margin and changing peak credits to a regional level, would
increase the LOLP. This analysis illustrates the level of market reliance created in the RA
program would not be materially different than Avista’s current assumption for market
availability by only yielding a change in LOLP by 1 percent.

Table 12.23: Portfolio Scenario’s Reliability Analysis

Scenario Year
Studied
LOLP LOLH LOLE EUE
1- Preferred Resource Strategy 2030 5.4% 1.74 0.14 266
5- Clean Resource Plan (2027) 2030 5.7% 1.66 0.13 250
6- Clean Resource Plan (2045) 2040 7.5% 2.98 0.22 643
10- RA Program 2030 6.4% 2.67 0.20 510
16- Colstrip Exit 2035 2030 5.7% 1.77 0.14 287

Market Price Sensitivities
Another way to measure risk for each portfolio is to compare each portfolio’s cost under
different specific market conditions rather than relying on the stochastic study. This
section compares each portfolio using the electric price scenarios described in Chapter
10. The scenarios include a deterministic study of the Expected Case (Sensitivity 1), while
fixing the major risk variables such as hydro conditions and natural gas prices at expected
averages. Sensitivity 2 is low natural gas prices; Sensitivity 3 is high natural gas prices;
and Sensitivity 4 is the SCC as a tax across the entire Western Interconnect. Avista only
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 275 of 317
Chapter 12: Portfolio Scenario Analysis

Avista Corp 2021 Electric IRP 12-43
conducted these market scenarios on portfolios with implications of changes in market
prices to understand the sensitivity to major assumption changes.

The following tables show the change in cost (PVRR) and levelized emitted greenhouse
emissions given these pricing sensitivities. Table 12.24 shows the cost changes
compared to the Expected Case revenue requirements from the deterministic price
forecast. In all portfolios, higher natural gas prices lead to higher costs, but portfolios with
either more renewables or more coal are less cost sensitive. For the fuel price sensitivity
with low natural gas prices, all portfolios have lower costs and portfolios with more coal
and renewables are less cost sensitive. The SCC as a tax sensitivity changes the least
cost portfolio results. In this case, a high price national carbon tax places the #5 and #6
Clean Resource Portfolios as the best options. From a greenhouse gas reduction
perspective, the results perform as expected. Where higher natural gas prices occur,
Avista’s natural gas dispatch is reduced and where natural gas prices are lower, Avista’s
natural gas fleet operates more. The SCC scenario reduces all emissions as intended.

The second view of these market scenarios (Table 12.25) compares the alternative
portfolios to the PRS to see if any portfolios perform better with these price sensitivities.
In an alternative future, retaining Colstrip performs better in a higher natural gas price
environment, but the Portfolio #3 Baseline 2 where no clean energy is added performs
better in a lower natural gas price future, illustrating the cost of clean energy. In the case
of the national SCC tax future, the Portfolio #5 2027 Clean Resource Plan performs best.
The greenhouse gas analysis of this comparison shows marginal changes compared to
the PRS except for when Colstrip exits the portfolio. The Portfolio #6 Clean Resource
Plan (2045) scenario emissions are higher due to one Colstrip unit staying on-line as
described earlier in this chapter. Otherwise emissions would be similar to Portfolio #5.

Table 12.24: Change in Cost (PVRR) Compared to Expected Case

Portfolio
SCC SCC
1- Preferred Resource Strategy 6.1% -2.1% 5.5%-18% 16% -18%
3- Baseline 2 8.8% -3.0% 11.5%-18% 17% -18%
5- Clean Resource Plan (2027) 3.6% -1.3% -0.1%-18% 16% -18%
6- Clean Resource Plan (2045) 2.6% -0.9% 0.0%-12% 6% -25%
15- Colstrip Exit 2025 5.7% -2.0% 5.7%-14% 11% -23%
16- Colstrip Exit 2035 5.2% -1.8% 6.6%-11% 5% -30%
17- Colstrip Exit 2045 4.8% -1.7% 7.3%-10% 3% -31%
Change in PVRR vs Expected
Case Expected Case
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 276 of 317
Chapter 12: Portfolio Scenario Analysis

Avista Corp 2021 Electric IRP 12-44
Table 12.25: Levelized Greenhouse Gas Emissions vs. Expected Case

Social Cost of Carbon Portfolio Optimization
The previous section comparing the portfolios to a future with the SCC as a national tax
is interesting, but they may not lead to the best portfolio if the carbon tax is considered
when optimizing the portfolio. Avista conducted an analysis to determine the optimal
portfolio with this SCC assumption. In this case, the cost can be improved by 2.5 percent
over the PRS and 0.8 percent better than Portfolio #5 with similar greenhouse gas
emissions. The selected portfolio in this future is shown in Table 12.26 This portfolio uses
88 MW less natural gas than the PRS, 77 MW less solar and replaces the capacity with
storage and wind generation in addition to higher amounts of energy efficiency.

Portfolio
SCC SCC
3- Baseline 2 0.7% -2.7% 3.8%1% 1% 1%
5- Clean Resource Plan (2027) 1.3% 4.7% -1.8%-1% -2% -1%
6- Clean Resource Plan (2045) 2.0% 6.8% 0.0%33% 13% 13%
15- Colstrip Exit 2025 -0.1% 0.4% 0.4%23% 13% 11%
16- Colstrip Exit 2035 -0.5% 0.7% 1.4%59% 32% 25%
17- Colstrip Exit 2045 -0.8% 0.8% 2.1%75% 41% 34%
Change in PVRR vs PRS
PRS
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 277 of 317
Chapter 12: Portfolio Scenario Analysis

Avista Corp 2021 Electric IRP 12-45
Table 12.26: Optimized Social Cost of Carbon Future Portfolio

Resource Type Year State Capability
Colstrip 2021 WA/ID (222)
NW Off System Wind 2023 WA 250
Montana Wind 2023 WA 100
Montana Wind 2025 ID 100
Post Falls Upgrade 2026 WA/ID 8
Lancaster 2026 WA/ID (257)
Montana Wind 2026 WA/ID 200
Kettle Falls Upgrade 2026 WA/ID 12
Natural Gas Peaker 2027 WA/ID 125
Rathdrum Upgrade 2029 WA/ID 5
Natural Gas Peaker 2031 WA/ID 55
NW Hydro Slice 2031 WA/ID 75
Northeast 2035 WA/ID (54)
Solar w/ storage (4 hours) 2035 WA/ID 100
4-hr Storage for Solar 2035 WA/ID 50
Natural Gas Peaker 2036 WA/ID 66
Solar w/ storage (4 hours) 2037 WA/ID 111
4-hr Storage for Solar 2037 WA/ID 56
Solar w/ storage (4 hours) 2039 WA/ID 100
4-hr Storage for Solar 2039 WA/ID 50
4hr Lithium-Ion 2040-2043 ID 176
4hr Lithium-Ion 2040-2045 WA 824
Boulder Park 2040 WA/ID (25)
Solar w/ storage (4 hours) 2041 WA/ID 100
4-hr Storage for Solar 2041 WA/ID 50
NW Off System Wind 2044-2045 ID 227
Distribution Scale 4hr Lithium-Ion 2044-2045 WA 41
NW Off System Wind 2044 WA/ID 123
Distribution Scale 4hr Lithium-Ion 2045 WA/ID 9

Supply-side resource net total (MW) 2,456
Supply-side resource total additions (MW) 3,014
Demand Response 2045 capability (MW) 42
Cumulative energy efficiency (aMW) 152
Cumulative summer peak savings (MW) 177
Cumulative winter peak savings (MW) 133

Climate Shift Portfolio Optimization
Avista conducted a study to determine the effects to and cost of the Avista portfolio with
temperatures continuing to warm and changing Avista’s historical load and hydro profiles.
These changes are discussed earlier in Chapter 3 for load and Chapter 10 for hydro
conditions. In summary, average annual loads levels do not significantly vary, but winter
peak loads are 63 MW lower by 2045 and summer peak loads are 55 MW higher
respectively. As for hydro conditions, Avista’s production is expected to increase 15 aMW
for the Clark Fork and Spokane River systems over the year with lower expected hydro
production in the spring and summer and higher hydro production in the winter months.
From a hydro production point of view, these changes will reduce the cost to serve
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 278 of 317
Chapter 12: Portfolio Scenario Analysis

Avista Corp 2021 Electric IRP 12-46
customers. Figure 12.17 demonstrates the changes in Avista load and resource balance
given these potential future weather conditions. The warmer temperatures on a net basis
decrease the need for more winter resources but increase the need for summer
resources. Even with these changes, by 2045 Avista will still require more winter capacity
than summer capacity due to higher winter planning margins. The gap of seasonal need
goes from 129 MW to 27 MW by 2045. Although, Avista may find with these weather
changes a higher planning margin may be required for summer which could increase the
need for summer resource acquisitions.

Figure 12.17: Climate Shift Land and Resource Position Change

Given these changes, a re-optimized portfolio was developed, and it is shown in Table
12.27. This portfolio is like the PRS, but with 43 MW less natural gas CTs, less solar
generation, but the model selects more summer peaking energy efficiency programs.
From a cost perspective, the average system costs decline by 1.1 percent over the 24-
year period. Currently, Avista is unable to conduct a reliability study of the portfolio due
to the complexity of the future distributions of hydro and load. Avista plans to conduct
such a study in a future IRP.

(60)
(40)
(20)
-
20
40
60
80
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Me
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/
A
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M
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Winter
Summer
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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 279 of 317
Chapter 12: Portfolio Scenario Analysis

Avista Corp 2021 Electric IRP 12-47
Table 12.27: Optimized Social Cost of Carbon Future Portfolio

Resource Type Year State Capability
Colstrip 2021 WA/ID (222)
Montana Wind 2023 WA 100
Montana Wind 2025 WA 100
Post Falls Upgrade 2026 WA/ID 8
Lancaster 2026 WA/ID (257)
Natural Gas Peaker 2027 ID 84
Natural Gas Peaker 2027 WA/ID 85
Montana Wind 2028 WA 100
NW Hydro Slice 2031 WA 75
Northeast 2035 WA/ID (54)
Rathdrum Upgrade 2035 WA/ID 5
Natural Gas Peaker 2036 ID 36
Kettle Falls Upgrade 2036 WA/ID 12
Rathdrum Upgrade 2036 WA/ID 4
Natural Gas Peaker 2036 WA/ID 87
Solar Photovoltaic 2039-2040 WA 10
Boulder Park 2040 WA/ID (25)
Montana Wind 2041 WA 100
Solar w/ storage (4 hours) 2042-2043 WA 222
4-hr Storage for Solar 2042-2043 WA 111
Liquid Air Storage 2044-2045 WA 21
Solar Photovoltaic 2045 ID 5
Solar Photovoltaic 2045 WA 140

Supply-side resource net total (MW) 748
Supply-side resource total additions (MW) 1,306
Demand Response 2045 capability (MW) 64
Cumulative energy efficiency (aMW) 127
Cumulative summer peak savings (MW) 139
Cumulative winter peak savings (MW) 116

Washington Maximum Customer Benefit Scenario
The maximum customer benefit scenario is a limited economic optimization study to help
understand the cost of adding or removing resources from the portfolio to maximize non-
energy benefits to Washington customers. Non-energy benefits include societal benefits
such as health, local economic development, improved reliability, customer satisfaction
among others. To better understand these societal benefits, Avista will identify these
benefits or costs to its customers and system in the next IRP. While the customer value
of non-energy benefits is yet to be determined, this scenario takes resource selection to
the extreme where customers may benefit without fully taking cost into account.

This scenario assumes new resources provide economic benefits if located in
Washington rather than other locations and ignores the cost of the selection decision. It
only considers if the choice to locate a resource in Washington has more benefits than
locating the resource in another state. In the end, the total portfolio cost of all the decisions
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 280 of 317
Chapter 12: Portfolio Scenario Analysis

Avista Corp 2021 Electric IRP 12-48
could then be weighed against the theoretical customer benefit if known and the
alternative resource portfolio such as the PRS.

This analysis also assumes customers benefits by maximizing local distributed energy
resources (DERs) given the system’s ability to integrate such systems. The analysis does
not however determine if DERs provide benefit to customers from a reliability or resiliency
point of view since Avista does not find additional DERs will increase customer reliability
or resiliency unless these systems are behind the customer’s meter under customer
control or if a separately controlled micro grid facilitates system operations for a limited
number of customers3. The scenario does not consider the additional distribution systems
cost to facilitate a change in grid operations for supporting additional DERs.

The scenario takes two approaches for determining resource selection. The first approach
adds demand-side resources such as energy efficiency and demand response to the
maximum potential. The next step adds DERs to the maximum capability of the system
such as customer owned solar and utility owned distributed solar and storage. The last
step allows the PRiSM model to optimize the remaining portfolio with resource choices
beneficial to Washington customers such as no new natural gas, resource acquisitions in
Washington only and limiting REC purchases from Idaho customers. Table 12.28 shows
a description of each of these assumptions and the potential customer benefits.

As previously discussed, the value to Avista’s customers for the resource selection
choices is not known, but the incremental value of all these choices are known compared
to the PRS. The PVRR of costs increases from $8.70 billion in the PRS to $10.76 billion
in this scenario. The energy rate also increases to customers from 12.7 cents/kWh to 16.6
cents/kWh in 2030. By 2045, this rate increases to 25.9 cents/kWh compared to the PRS’s
17.3 cents/kWh. This scenario provides annual power cost risk reduction compared to the
PRS by reducing annual standard deviation from $87 million to $73 million. In addition to
this risk reduction, direct greenhouse gas emissions fall from 0.54 million metric tons in
2045 to 0.44 million metric tons with the scenario assumptions.

3 See system reliability of DERs in chapter 8 for more information.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 281 of 317
Chapter 12: Portfolio Scenario Analysis

Avista Corp 2021 Electric IRP 12-49
Table 12.28: Customer Benefits

Assumption Energy/ Non-Energy
Impacts
Public Health/
Environmental Health/
Reliability/ Resilience
Increased energy
efficiency by 57
aMW through 20454.
 Comfort &
Productivity
 Increase local
employment
 Customer
engagement
 Acts as hedge against
price volatility
 Customer health
 Reduction in employee
sick days.
 Reduction of power
plant emissions.
 Decreased water use
 Heat & cooling retention in
outages.
 System and local peak
reductions to lower new
resource requirements.
Increase demand
response by 124
MW5 .
 Customer
engagement and
loyalty
 Increase local
employment
 Bill savings for
participation
 Unknown changes in
regional power plant
emissions.
 System and local peak
reductions to lower new
resource requirements.
 Aid in managing
frequency and regulation
400 MW of 8-hour
duration distribution
level storage by
2045.
 Potential for deferred
distribution
investments  Increase local
employment
 Increase local tax
base
 Potential for reduced
wildfire risk by
temporarily shutting
down Transmission
lines.
 Potential for decreased
power outage length in
microgrid or behind meter
installation.
400 MW (AC) of
utility distributed
small scale solar.
 Increase local
employment
 Increase local tax
base
 Potential for regional
power plant emission
reductions.
 Benefits are yet to be
determined.
620 MW (AC) of
roof-top solar6 .
 Increase local
employment
 Increase local tax
base
 Potential for regional
power plant emission
reductions.
 Potential for customer
reliability benefits if
coupled with customer
storage.
No new natural gas
facilities7.
 Increase capital
investment in other
resources.
 Reduction of power
plant emissions
 Less reliance on single
natural gas supply line.
No hydro renewable
energy credit
transfers from Idaho
customers.
 Increase local
employment
 Increase local tax
base
 Potential for regional
power plant emission
reductions.
 Benefits are yet to be
determined.
No out of state
renewables
including solar,
wind, or geothermal.
 Local job creation
 Increase tax base
 Benefits are yet to be
determined.
 Benefits are yet to be
determined.
No new nuclear
resources.
 Elimination of nuclear
waste storage
 Elimination of
catastrophic failure risk
 Benefits are yet to be
determined.

4 Assumes up to $1000 per MWh for avoided cost.
5 Includes all demand response options under $1000 per kW-year.
6 Modeled as utility scale rather than a load reduction using pricing for utility scale distributed solar.
7 Includes upgrades to existing resources.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 282 of 317
Chapter 12: Portfolio Scenario Analysis

Avista Corp 2021 Electric IRP 12-50
Table 12.29: Optimized Social Cost of Carbon Future Portfolio

Resource Type Year State Capability
Colstrip 2021 WA/ID (222)
Small Scale Solar 2022-2030 WA 403
NW Wind 2023 WA 143
8 hr Lithium-Ion (Distribution) 2022-2030 WA 100
Post Falls Upgrade 2026 WA/ID 8
Rathdrum Upgrade 2026 WA/ID 5
Kettle Falls Upgrade 2026 WA/ID 12
Liquid Air Storage 2027 WA 110
Natural Gas CT 2027 ID 113
Small Scale Solar 2031-2040 WA 495
8 hr Lithium-Ion (Distribution) 2031-2040 WA 200
NW Hydro 2031 WA/ID 75
Northeast 2035 WA/ID (54)
Natural Gas CT 2036 ID 59
Boulder Park 2040 WA/ID (25)
Small Scale Solar 2041-2045 WA 104
8 hr Lithium-Ion (Distribution) 2041-2045 WA 100
Liquid Air Storage 2043-2045 ID 34
Solar w/ storage (4 hours) 2045 WA 100
4-hr Storage for Solar 2045 WA 50

Supply-side resource net total (MW) 1,810
Supply-side resource total additions (MW) 1,509
Demand Response 2045 capability (MW) 179
Cumulative energy efficiency (aMW) 179
Cumulative summer peak savings (MW) 244
Cumulative winter peak savings (MW) 142

Expected Case Portfolio Summary
A summary of the total new resources selected between 2022 and 2045 is shown in Table
12.30 for all portfolios using the Expected Case market forecast. In addition to this
summary, all PRiSM models and summary information is available in Appendix I.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 283 of 317
Chapter 12: Portfolio Scenario Analysis

Avista Corp 2021 Electric IRP 12-51
Table 12.30: 2022-2045 Portfolio Selection Summary

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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 284 of 317
Chapter 12: Portfolio Scenario Analysis

Avista Corp 2021 Electric IRP 12-52

This Page Intentionally Left Blank

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 285 of 317
Chapter 13: Energy Equity

Avista Corp 2021 Electric IRP 13-1
13. Energy Equity

Washington’s Clean Energy Transformation Act (CETA) requires utilities to ensure an equitable
distribution of energy and non-energy benefits and a reduction of burdens on vulnerable
populations and highly impacted communities. Avista has a history of demonstrated
commitment to easing the energy burden for vulnerable customers through several programs
and community partnerships. This is evident from the Company’s robust outreach program, with
multiple modalities, designed to equip customers with conservation education information and
resources along with raising awareness of assistance programs among vulnerable customers
including low-income, senior and disabled. Avista’s commitment is also demonstrated through
bill assistance and weatherization programs in place to help customers with affordability and
energy efficiency. The equity components of CETA provides the Company with an opportunity
to dig deeper into its commitment to ensure safeguards are in place for marginalized groups of
customers impacted by Avista resource plan, giving these customers a voice and access to
benefits as we move toward a cleaner power supply.

In addition to specific initiatives for vulnerable customers, Avista has many other indirect
programs to serve all customer groups including park development, the energy pathway career
experience program for high school students, wildlife land purchases, transportation
electrification and public access to Avista recreational properties to name a few. The CETA
guidelines will expand these efforts with enhanced funding for additional low-income programs,
higher energy efficiency targets and other specific targeted programs and projects developed
with input from the Equity Advisory Group discussed in this chapter.

Avista is in the early stages of developing a plan for addressing the new CETA equity goals.
The Company started by conducting an analysis to identify potential geographically based
communities using vulnerable population data. The analysis compares energy use in the
communities to other customers along with the percent of annual income consumed by energy
costs. Lastly, the Company compared reliability and resilience data of these communities to
customers outside of these areas. These analyses provided an initial point of reference to
measure success of future programs and to understand whether the correct geographic areas
or population groups identified as vulnerable are accurate. This will be an ongoing analysis to
identify the locations of Vulnerable Populations in our service area as demographics shift. At
this time, the analysis and requirements discussed in this section only apply to Washington
Section Highlights
 A preliminary methodology for determining vulnerable communities within Avista’s
service territory is complete.
 A baseline process and analysis are complete to assess energy use, energy burden,
air emissions and community reliability and resiliency.
 Avista is forming an Equity Advisory Group in early 2021 to enhance the Vulnerable
Population and Highly Impacted Community Action Plan.
 Avista plans to engage the public about the needs of both vulnerable and highly
impacted communities with the assistance of the Equity Advisory Group for refining
the future planning process.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 286 of 317
Chapter 13: Energy Equity

Avista Corp 2021 Electric IRP 13-2
State, but future IRPs may expand this work to include Idaho customers.

CETA Requirements
Specifically, CETA Section 1(6) requires:
The legislature recognizes and finds that the public interest includes, but is not
limited to:
 The equitable distribution of energy benefits and reduction of burdens to
vulnerable populations and highly impacted communities;
 long-term and short-term public health, economic, and environmental
benefits and the reduction of costs and risks;
 and energy security and resiliency.

It is the intent of the legislature that in achieving this policy for Washington, there
should not be an increase in environmental health impacts to highly impacted
communities.

The requirements are further defined for integrated resource planning in Section 14(k):

An assessment, informed by the cumulative impact analysis conducted under
section 24 of this act, of: Energy and nonenergy benefits and reductions of
burdens to vulnerable populations and highly impacted communities; long-
term and short-term public health and environmental benefits, costs, and
risks; and energy security and risk;

An Equity Advisory Group is being formed to help define the customers qualifying as vulnerable
populations. This group will develop an outreach plan to engage with these customer groups to
determine the energy needs of these communities and to develop a long-term strategy with the
interim steps the utility will take to equitably distribute energy and non-energy benefits and
reduce burdens for highly impacted communities and vulnerable populations.

The two types of qualifying customer communities for equity considerations under CETA are
Highly Impacted Communities and Vulnerable Populations. The Highly Impacted Communities
are communities designated by the department of health based on cumulative impact analyses
or a community located in census tracts that are fully or partially on "Indian country" as defined
in 18 U.S.C. Sec. 1151. At the time of this IRP, the Department of Health had not released
these areas1. Avista has two known qualifying census tracks within its Washington service
territory that are identified as “Indian country” including the Colville and Spokane reservations.

The second qualifying group for equity considerations are Vulnerable Populations. These are
communities that experience a disproportionate cumulative risk from environmental burdens
due to: (a) Adverse socioeconomic factors, including unemployment, high housing and
transportation costs relative to income, access to food and health care, and linguistic isolation;
and (b) Sensitivity factors, such as low birth weight and higher rates of hospitalization. Avista
assumes the identification of vulnerable populations will be determined by the utility with

1 Avista received the list of Highly Impacted Communities from the Department of Health on March 16, 2021.
Avista is reviewing the selected areas for inclusion in the 2023 IRP.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 287 of 317
Chapter 13: Energy Equity

Avista Corp 2021 Electric IRP 13-3
guidance by the Equity Advisory Group using the above factors.

This IRP is limited in the inclusion of these public interest requirements mainly due to the newly
developing public interaction process, as well as the complexity and timing of the CETA
rulemaking process. Additional energy efficiency for customers is not included in this IRP to
avoid double-counting due to the inclusion of non-energy benefits and the economic test
analysis for the social cost of carbon. In addition, the Company is committed to an energy
efficiency pilot project in 2021 to help vulnerable populated communities along with continuing
to provide and expand current efficiency and economic programs to its low-income
communities. Lastly, Avista is committed to conducting an analysis for nonenergy impacts of
generation alternatives for the next IRP with the aid of a specialist in this area.

Community Identification
Early in this IRP development, Avista found it beneficial to start a process to distinguish
vulnerable populations based upon the CETA definition. The challenge with this requirement
that remains unclear is whether these populations are based on geographic or individual
considerations.

A focus on geographic considerations allows the Company to resolve potential issues with
projects improving reliability/resiliency or economic stimulus from the location of future power
generation. It can also help identify equity concerns related to emissions. The downside to this
methodology, and benefit of identifying these communities on an individual basis, allows for
customers who live in areas not determined to be vulnerable to also be considered for
programs. Regardless of their geographic location, customers who meet the vulnerable
definition would still be eligible for income-qualified assistance programs.

At this time, and subject to future agreement by the Equity Advisory Group, Avista chose to use
a geographic method to identify these communities. Avista leveraged the Environmental Health
Disparities Map2 analysis conducted by the Washington Department of Health (DOH). Avista
chose this methodology as it coincides with CETA’s definition of Vulnerable Populations. The
DOH map divides Washington into local areas using Federal Information Processing Standards
(FIPS) codes; which are generally areas within counties or cities representing neighborhoods.
Figure 13.1 illustrates the boundaries of these areas based on the scoring of the final composite
score between pollution burden and population characteristics (used for illustration purposes
only).

2 https://fortress.wa.gov/doh/wtn/wtnibl/
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 288 of 317
Chapter 13: Energy Equity

Avista Corp 2021 Electric IRP 13-4
Figure 13.1: Washington Department of Health Disparities Map

A rating between 1 and 10 is given for Pollution Burdens and Population Characteristics in each
of these areas. The ratings are based on a score of 5 being median within the state and the
higher or lower scores are based on a percentile of the population. Avista chose to use the
Population Characteristics metrics as these are defined with a scoring of 1 to 10 for both
Sensitive Population considerations including cardiovascular disease and low birth weight
infants as well as Socioeconomic Factors such as poor educational attainment, housing burden,
linguistic isolation, poverty, race, transportation expense and unemployment. These definitions
of scoring are consistent with the definition of Vulnerable Populations from CETA. Other
considerations to enhance these selections will be discussed and considered with the Equity
Advisory Group.

The next step in identifying Vulnerable Populations is to align the DOH health disparities map
with Avista’s service territory using its Geographic Information System (GIS). Avista chose to
include any area with a score of 8 or higher in either the Sensitive Population or Socioeconomic
Factor rating as a Vulnerable Population. This score indicates a population base with
characteristics exceeding the 70th percentile in the category. Avista plans to refine this selection
with guidance from the Equity Advisory Group. Avista expects this will be an ongoing
requirement as local demographics change. The vulnerable areas are shown in Figure 13.2 for
eastern Washington and in Figure 13.3 for the Spokane area.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 289 of 317
Chapter 13: Energy Equity

Avista Corp 2021 Electric IRP 13-5
Figure 13.2: Vulnerable Population Areas within Avista Service Territory

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 290 of 317
Chapter 13: Energy Equity

Avista Corp 2021 Electric IRP 13-6
Figure 13.3: Vulnerable Population Areas within Spokane Area

Avista’s Washington electric service territory serves either the entirety or a portion of 145
communities using the FIPS code methodology. Of Avista’s 145 communities, 35 (24 percent)
score 8 or higher in the Sensitive Population category and 55 (38 percent) have Socioeconomic
Factors communities scores of 8 or higher. When combining either area with a score of 8 or
higher, 67 (46 percent) of communities within Avista’s service territory qualify as Vulnerable
Populations. This compares to the statewide statistics of 43 percent of the 1,458 communities
qualifying as vulnerable. Avista’s service territory has a higher density of lower Socioeconomic
areas with a score of 8 or higher (28 percent) than the state average but higher Sensitive
Population scores (30 percent) than the state average. Given the large amount of areas
qualifying, the Equity Advisory Group may need to consider narrowing the qualifications for
consideration.

Table 13.1 compares the number of areas qualifying as vulnerable or Highly Impacted based
on different metrics of scoring from the DOH methodology. The table shows how many areas
would be affected if levels other than scores of 8 or above were used.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 291 of 317
Chapter 13: Energy Equity

Avista Corp 2021 Electric IRP 13-7
Table 13.1: Percent of Service Territory Area Above the DOH score

Score Socioeconomic Sensitive
Populations
Either
Category
6+ 45%60%68%
7+ 33%49%57%
8+ 24%38%46%
9+ 13%22%29%
10 6%12%16%

Another method might consider total score of both categories. This methodology could narrow
the areas to high levels of both areas of focus rather than just one area. While there are many
ways to use this data and potentially other data sources, Avista plans to address the final
selection of a methodology with guidance from the Equity Advisory Group.

Baseline Analysis
Avista developed a baseline analysis of the selected areas to determine where there are
significant differences in energy use, energy cost, reliability, resiliency and higher densities of
locational power plant emissions. These analyses can be useful for multiple purposes. The first
benefit can be using this baseline to measure success of future programs to ensure a positive
change. The other benefit of the baseline could be to provide additional criteria for the Equity
Advisory Group to narrow or expand areas for inclusion in future program development.

Energy Use, Cost and Burden Analysis
The results of the usage and energy burden analysis are available in Tables 13.2 and 13.3
using data between 2015 and 2019. The income estimates use census level income information
for each area. The usage and utility bill costs are from Avista’s customer database. The first
table of electric only customers show the areas with DOH scores above 8 use slightly less
electric energy then other areas; therefore, their bills are also lower. However, as a comparison
of energy bills as a percent of income, these areas spend more of their income on energy,
which is known as energy burden. What is not distinguished in this information is whether other
heating fuels influence these amounts, along with home types, square footage or home location
which may be included in future analyses.

Table 13.2: Electric Energy Use and Energy Burden Comparison

Area Fuel Type Monthly
Energy
Use
(Kwh)
Monthly
Avg Bill
Annual
Household
Income
%
Income
or
Energy
Vulnerable Population Areas Electric 997.7 $98.40 $42,730 2.8%
Other Areas Electric 1,009.7 $100.20 $58,834 2.0%

Table 13.3 includes analysis on customers with both electric and natural gas usage as part of
the calculation as it is more likely to estimate a total household energy cost compared to income
and the home types are likely to be similar, meaning a lower probability of multi-family houses
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 292 of 317
Chapter 13: Energy Equity

Avista Corp 2021 Electric IRP 13-8
with more than two units. In this scenario, energy use as a percent of income is higher. It is
noteworthy this total measurement shows higher cost percent of income, but not over a typical
6 percent threshold for energy burden. Some of these communities may have other reasons to
identify them with higher ratings using the DOH metric other than low income.

Table 13.3: Electric & Natural Gas Energy Use and Energy Burden Comparison

Area Fuel Type Energy Use Average
Monthly
Bill $
Annual
Household
Income $
Income
% or
Energy
Vulnerable Population Areas Electric 820.4 kWh $80.40
Other Areas Electric 875.5 kWh $84.50

Vulnerable Population Areas Natural Gas 51.6 Dth $47.40
Other Areas Natural Gas 62.3 Dth $55.90

Vulnerable Population Areas Total $127.80 44,889 3.4%
Other Areas Total $140.30 68,250 2.5%

While the summary level information is useful, drilling down into the individual areas is just as
important. Figure 13.4 illustrates the electric only customer scoring for areas with DOH scores
8 and above. In this case the darker color areas have higher energy cost compared to income;
but as a total area no electric only customers exceed 4.27 percent of energy cost compared to
income. Other studies show many individual customers exceed these amounts for energy
burden.

The combined electric and natural gas customer information is in Figure 13.5. This figure, with
the inclusion of total energy and total energy cost, shows areas within Spokane and Pullman
whose costs exceed the 6 percent threshold. This information may help identify areas where
the Equity Advisory Committee may want to focus programs for energy assistance or targeted
energy efficiency programs.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Figure 13.4: Electric Customer Energy Cost versus Income

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Figure 13.5: Electric/Natural Gas Customer Cost versus Income

Reliability and Resiliency Analysis
As with the initial analysis regarding cost for the selected communities, Avista looked at
reliability to determine a baseline of areas within the service territory with reliability or resiliency
issues. The Company views resiliency and reliability as related terms. Measuring resiliency as
when an outage occurs and considers how long it takes to return service to customers. If
reliability is 100 percent, the system is also resilient as there are no outages to return service
from. The data presented in this section look at occurrences of outages and the time to return
to service for areas with the DOH score of 8 or above versus other customers.

Overall, Avista found that areas in the vulnerable areas have shorter outages over the five-year
period between 2015 and 2019. This is shown in Figure 13.6 for the Customer Average
Interruption Duration Index (CAIDI). CAIDI is a measure of resiliency to determine the average
number of minutes customers are offline during an outage. In the case of this historical period,
the duration is only slightly shorter. Response times for vulnerable customers could be shorter
due to the fact many are located in suburban areas where Avista is able to respond to outages
faster than in rural areas.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Avista Corp 2021 Electric IRP 13-11
Figure 13.6: CAIDI Historical Comparison

Figure 13.7 shows the Customers Experiencing Multiple Interruptions (CEMI) metric and it is a
measure of reliability. This metric indicates the number of outages on average that occurred in
these areas over the historical period. These results show there are slightly more outages in
the vulnerable areas then other areas of the system. Additional research of these results
showed the number of outages for vulnerable areas is likely due to a higher number of outages
in rural areas. In this case, vulnerable rural areas have 40 percent more outages (about one
more per year) than other rural areas, and the time to restore rural vulnerable customers is 11
percent longer or 25 minutes with the extra time needed to get crews out to the outage locations.

Figure 13.7: CEMI Historical Comparison

0
50
100
150
200
250
2015 2016 2017 2018 2019 5 yr Avg
Mi
n
u
t
e
s

p
e
r

E
v
e
n
t
Vulnerable Areas
Non-Vulnerable Areas
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Avista Corp 2021 Electric IRP 13-12
The detailed outage rates for the five-year average period is shown in map form in Figure 13.8
for the resiliency measurement of CAIDI and in Figure 13.9 for the reliability measurement
CEMI. It is clear in the map that rural areas to the north of Spokane are at a potential
disadvantage compared to other customers for reliability due to the local environment, distance
between customers and more extreme weather. Avista anticipates this exercise may help
determine the issues customers face in these areas and could lead toward identifying solutions
to resolve these concerns.

Figure 13.8: 5-year Average CAIDI Map

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Avista Corp 2021 Electric IRP 13-13
Figure 13.9: 5-year Average CEMI Map

Power Plant Locational Discussion
CETA objectives regarding equity provisions highlight concerns about the location of power
plants in areas with Vulnerable Populations and Highly Impacted Communities. Many of the
Avista-owned and contracted power plants are within the boundaries of the identified
communities with scores of 8 or higher as described above. Locating power plants in these
areas may have both positive and negative effects. Positive effects include economic
opportunities for job creation, added local tax base, greater energy security, and the potential
for increased resiliency. The negative impacts can be from air emissions, increased traffic from
construction and operations and visual concerns from transmission lines or other power
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Avista Corp 2021 Electric IRP 13-14
facilities. Table 13.4 highlights the facilities Avista owns or contracts3 for in the areas identified
with DOH scores above 8.

Table 13.4: Existing Facilities within Identified Areas

Facility Fuel Type Control County
Little Falls Water Own Stevens/Lincoln
Long Lake Water Own Spokane
Nine Mile Water Own Spokane
Upper Falls Water Own Spokane
Monroe Street Water Own Spokane
Northeast Natural Gas Own Spokane
Boulder Park Natural Gas Own Spokane
Adams Neilson Solar Contract Adams
Rattlesnake Flat Wind Contract Adams
Boulder Park Solar Solar Own Spokane
Upriver Water Contract Spokane

Even if a facility is not located in a vulnerably populated area, air emissions may have effects
on neighboring communities. Avista’s thermal facilities in the State of Washington meet state
level requirements for each emission type in their air permits, such as particulate matter and
nitrogen oxides. In addition, the retirement of two natural gas-fired facilities located in
Washington are being planned within the time horizon of this IRP; specifically, Northeast by
2035 and Boulder Park by 2040. Both facilities are “peaking” plants meaning they only run when
demand is extremely high and therefore have low annual emissions. The Northeast facility is
limited to 100 hours of operation per year and often runs less than 100 hours. Additional
information regarding emissions from Avista facilities is available in Appendix I. A future
analysis of the economic and health impacts of these facilities is being planned for the next IRP
as part of the non-energy impacts study for supply-side resources.

While IRPs are useful planning documents, actual resource selection and locational analysis is
determined through the Request for Proposal (RFP) process. Avista’s 2020 Renewables RFP
included additional scoring criteria for projects enhancing the economic viability of identified
vulnerable communities and projects located within the Avista Transmission system that may
enhance energy security and resiliency.

Vulnerable Population Action Plan
Avista’s Vulnerable Population Action Plan supports the objectives of the equitable distribution
of benefits and the reduction of health, economic and/or environmental burdens with the
following tactics:

1) Form an Equity Advisory Group to guide and prioritize community and individual
outreach and engagement and to assist with the establishment of indicators and
strategies.

3 Avista is only highlighting facilities generating greater than 5 MW in Washington State in this table.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Chapter 13: Energy Equity

Avista Corp 2021 Electric IRP 13-15
2) Develop targeted energy assistance programs and funding for low income customers in
identified areas.
3) Conduct a non-energy impacts study for supply and demand-side resources.

Equity Advisory Group
Requirement: WAC 480-100-655 Public participation in a clean energy implementation
plan (CEIP).
WAC 480-100-655 (2) – A utility must maintain and engage an external equity
advisory group of stakeholders to advise the utility on equity issues including, but
not limited to, vulnerable populations designation, equity indicator development,
data support and development, and recommended approaches for the utility’s
compliance within WAC 480-100-610 (4)(C)(i).
– Participation to include environmental justice and public health advocates,
tribes, and representatives from highly impacted communities and
vulnerable populations in addition to other relevant groups.
– Meet regularly with Equity Advisory Group during the CEIP development
and implementation.
– Must provide reasonable advance notice of all equity advisory group
meetings.
– CEIP draft review with advisory groups 2 months before filing with the
Commission.

Avista is forming an Equity Advisory Group (EAG) responsible to review the indicators and
vulnerable populations identified by the previously described analysis in this section along with
the DOH’s cumulative impact analysis in order to identify weighting factors for compliance with
WAC 480-100-610 (4)(c)(i). Additionally, the EAG will help guide the design of the Vulnerable
Population outreach and engagement that will be used to distinguish and prioritize additional
indicators and solutions, as well as the development of the Clean Energy Implementation Plan
(CEIP). The EAG’s work will be conveyed to the Technical Advisory Committee (TAC), the
Energy Assistance Advisory Group (EAAG) and Energy Efficiency Advisory Group (EEAG) for
use in their respective work.

Avista began preliminary work to determine a framework including membership for our EAG
towards the end of 2020. Along with official representation from stakeholders from the
community, clean energy, equity and public health, the Company is committed to obtaining
representation for individuals from highly impacted communities. The anticipated DOH analysis
will be critical for identifying the communities for which representation will be sought. Avista
plans to engage community organizations who reach across the service territory as well as
Intent: to advise the utility on equity issues including, but not limited to, vulnerable
population designation, equity indicator development, data support and development, and
recommended approaches for the utility's compliance with WAC 480-100-610 (4)(c)(i).
The utility must encourage and include the participation of environmental justice and
public health advocates, tribes, and representatives from highly impacted communities
and vulnerable populations in addition to other relevant groups.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Avista Corp 2021 Electric IRP 13-16
tribal organizations, but also include specific individuals within identified communities. It is
anticipated the group will start small and will expand as the group gains shared understanding
and determines direction and approach.

Prior to recruitment, and with guidance from the EAAG and community partners, Avista will
design the role and expectations for the advisory group participants including the group’s
objectives and meeting frequency.

Avista plans to have the first Equity Advisory Group meeting in the first half of 2021. With an
advisory group in place, the work will begin to refine the Vulnerable Population determinates
based on the preliminary analytical work conducted by Avista and the DOH. Also, for 2021, the
group will advise the Company on an outreach and engagement campaign to obtain information
and determine needs of vulnerable customers for each community. Avista staff are researching
and learning about processes and methods that have demonstrated results in effective outreach
and engagement in other jurisdictions that will be helpful for the design and facilitation of a
needs assessment of the targeted vulnerable populations. In addition to helping to confirm
health, economic and/or environmental burdens, partnership with local public health
organizations that have experience in successfully engaging marginalized, hard to reach
populations will be essential.

This group will also contribute to the review of future IRPs, Clean Energy Action Plans and
Clean Energy Implementation Plans. One area of focus will discern how to implement equity-
based solutions while maintaining traditional least cost planning methodologies. Figure 13.10
illustrates how the Equity Advisory Group’s work will inform the Company’s other stakeholder
groups while supporting community engagement and participation for the IRP’s TAC process.

Figure 13.10: Equity Advisory Group Chart

Example Programs
Advisory Groups:
incorporate indicators
Equity Areas:
indicators defined within
each area
Equity Advisory Group
Access to Clean Energy
TAC, TE, EEAG, EAAG
Low-Income Community Solar
Energy Affordability
EEAG & EAAG
Percent of Income Payment Plan
Community Engagement &
Participation
TAC, EEAG, EAAG
Community based participatory program design
Community Improvement
TAC & EEAG
Distribution of microgrids
Health & Safety
TAC & EEAG
Low-Income Weatherization + Health Safety Repair
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Chapter 14: Action Items

Avista Corp 2021 Electric IRP 14-1
14. Action Items

The IRP is an ongoing and iterative process balancing regular publication timelines while
pursuing the best resource strategy for the future as the market, laws and customer needs
evolve. The biennial publication date provides opportunities to document ongoing
improvements to the modeling and forecasting procedures and tools, as well as enhance the
process with new research as the planning environment changes. This section provides an
overview of the progress made on the 2017 and 2020 IRP Action Plans and discusses plans
for the 2023 IRP. This discussion reviews the past two IRPs due to only officially filing the 2020
IRP in Idaho, but not Washington. Avista considers the Action Plan for the 2020 IRP to also
apply to this plan and intends to complete these items for the 2023 IRP and beyond.

Summary of the 2017 IRP Action Plan
The 2017 Action Plan included three categories: generation resource related analysis, energy
efficiency and transmission planning.

Generation Resource Related Analysis
 Continue to review existing facilities for opportunities to upgrade capacity and efficiency.

Avista included an upgrade to the Post Falls facility based on economics of the
upgrade in the 2020 IRP. Avista also included options for Rathdrum and Kettle Falls
facilities. This IRP also evaluated the potential for significant upgrades at Long Lake,
Monroe Street, Upper Falls and Cabinet Gorge. After additional review, Avista no
longer considers these upgrades to qualify for Washington’s clean energy
requirements as these changes are beyond efficiency improvements and make
substantial changes to capacity and water use. Although, Avista may still consider
these plans to continue to enhance existing resources where possible to help meet
future resource needs. Additional information regarding resource upgrades is
included in Chapter 9.

 Model specific commercially available storage technologies within the IRP; including
efficiency rates, capital cost, O&M, life cycle and the ability to provide non-power supply
benefits.

This IRP includes a range of storage resource technologies and durations as well
as considering Avista-owned and PPA options. The IRP studied the reliability
benefits of storage options with different durations. Avista included pumped hydro,
liquid-air and lithium-ion technologies. During this IRP cycle, energy storage costs
and technologies continued to change and develop. Avista will continue to analyze
new storage options and costs as a resource in addition to continuing its process in
optimizing the transmission and distribution systems to utilize storage when
beneficial to the local system. A full list of the storage resource options and
descriptions is available in Chapter 9.

 Update the TAC regarding the EIM study and Avista plan of action.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Avista Corp 2021 Electric IRP 14-2
Avista’s officers approved joining the EIM on April 15, 2019 and the Company plans
to go live with the EIM on March 2, 2022. Avista shared this update at the fifth TAC
meeting of the 2020 IRP on October 15, 2019. As part of joining the EIM, Avista
expects to spend approximately $32 million to enter the market and an additional
$4.0 million each year thereafter. The EIM will require at least 17 new employees to
support ongoing market operations. The benefits of the EIM range from $2 to $12
million per year but are likely to be nearly $6 million per year. The EIM presentation
shared with the 2020 IRP TAC is available in Appendix A of the 2020 IRP.

 Monitor regional winter and summer resource adequacy, provide TAC with additional Avista
LOLP study analysis.

The 2020 IRP’s second TAC meeting included a presentation regarding Avista’s
resource adequacy methodology and preliminary results of the system for 2030.
Avista also presented the TAC with ELCC calculations for each resource used for
resolving Avista capacity shortfalls. In the sixth TAC meeting, Avista shared results
from the PRS’s reliability analysis. The 2020 IRP Appendix A includes the slides
presented to the TAC and Chapters 9 and 11 include results from Avista’s reliability
studies. Avista used this same analysis for the 2021 IRP.

 Update the TAC regarding progress on the Post Falls Hydroelectric Project redevelopment.

Avista concluded in the 2020 IRP PRS analysis that the most cost-effective plan for
Post Falls was to redevelop the site by 2027 to maintain its Spokane River License.
The project scope includes replacing turbines and generators with more efficient
units that will generate additional capacity and energy. Avista compared this option
against replacing the equipment with similar sized technology. Avista shared this
progress at the second, fifth and sixth TAC meetings of the 2020 IRP. Those
presentations are available in the 2020 IRP Appendix A. Avista includes this
upgraded resource in its resource balance in the 2021 IRP.

 Perform a study to determine ancillary services valuation for storage and peaking
technologies using intra-hour modeling capabilities. Further, use this technology to estimate
cost to integrate variable resources.

Avista conducted studies regarding the benefits of pumped hydro storage and flow
batteries and shared results with the 2020 TAC at its fifth meeting. Avista believes
this analysis is important to meet future needs of the system and it requires tools to
correctly identify the costs and benefits. Avista plans to conduct additional analyses
once sub-hourly modeling is available in the ADSS system with the assistance of
intra-hour reserve requirements provided by EnerNex Consulting. Avista has not
completed this work and it will be an Action Item for the 2023 IRP.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Avista Corp 2021 Electric IRP 14-3
 Monitor state and federal environmental policies affecting Avista’s generation fleet.

Avista continues to monitor and participate in the development of state and federal
environmental policies affecting Avista’s generation fleet. Updates about the
ongoing impacts and changes to these policies are available in Chapter 4.

Energy Efficiency and Demand Response
 Determine whether to move the Transmission and Distribution (T&D) benefits estimate to a
forward-looking value versus a historical value.

Avista uses the Northwest Planning and Conservation methodology for evaluating
the benefits of energy efficiency to the Transmission and Distribution system. The
discussion of this methodology is in Chapter 5 of this plan.

 Determine if a study is necessary to estimate the potential and cost for a winter and summer
residential demand response (DR) program and along with an update to the existing
commercial and industrial analysis.

Applied Energy Group (AEG) conducted a DR potential study for Avista’s service
territory. The study included residential, commercial and industrial programs. AEG
presented the DR programs at the third TAC meeting in April 2019 for the 2020 IRP
and the September 2020 meeting for the 2021 IRP. Chapter 6 includes an overview
of these DR programs. Avista identified many of these programs as cost effective
and they are included in the PRS described in Chapter 11.

 Use the utility cost test (UCT) methodology to select conservation potential for Idaho
program options.

Avista included the UCT methodology for evaluating energy efficiency in Idaho.
Avista continues to use the TRC method in Washington. Details about energy
efficiency cost methodologies are in Chapter 5.

 Share proposed energy efficiency measure list with Advisory Groups prior to CPA
completion.

Avista provided a list of energy efficiency measures for the IRP to TAC members on
its website. This information is also available in Appendix I.

Transmission and Distribution Planning
 Work to maintain Avista’s existing transmission rights, under applicable FERC policies, for
transmission service to bundled retail native load.

Avista has maintained its existing transmission rights on its system and any
transmission system it purchases rights from to serve native load.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Avista Corp 2021 Electric IRP 14-4
 Continue to participate in BPA transmission processes and rate proceedings to minimize
costs of integrating existing resources outside of Avista’s service area.

Avista continues to actively participate in BPA transmission rate proceedings.

 Continue to participate in regional and sub-regional efforts to facilitate long-term economic
expansion of the regional transmission system.

Avista staff participates in and leads many regional transmission efforts including
the newly formed Northern Grid, which replaced Columbia Grid and the Northern
Tier Transmission Group.

 IRP and T&D planning will coordinate on evaluating opportunities for alternative
technologies to solve T&D constraints.

Avista conducted a pilot project to determine if a distribution project could be
modeled within PRiSM to co-optimize the power system along with the needs of the
T&D system. Chapter 8 of the 2020 IRP discusses this analysis. Avista plans to
continue this analysis in future IRPs. The 2021 IRP concluded that no projects met
the criteria for inclusion in the IRP.

2020 IRP Two Year Action Plan
Avista’s 2020 PRS provided direction and guidance for the type, timing and size of future
resource acquisitions in 2020. The 2020 Action Plan highlights the activities for development in
the 2021 IRP. These activities include resource acquisition processes, regulatory filings and
analytical efforts for the next IRP. This Action Plan includes input from Commission Staff,
Avista’s management team and members of the TAC. Avista is expanding this Action Items
section to be included in the 2023 IRP for any uncompleted items from the 2020 IRP due to the
short 2021 IRP schedule.

Resource Acquisition Action Items
 Determine the plan for Long Lake Development expansion. This includes a filing with the
appropriate agencies to determine if the project upgrades identified in this plan meet CETA
requirements. Begin discussions with agencies who are part of the Spokane River license
to discuss expansion options. Lastly determine if the project should include a new second
powerhouse, a new combined powerhouse including existing generation capacity or leave
the project unchanged. This Action Item will begin in 2020 and will be an ongoing item for
the 2021 IRP. Any updates will be shared with the TAC when available.

Avista completed a legal review of the requirements to qualify the Long Lake
Development expansion as a qualifying clean energy resource and does not
believe this upgraded resource would qualify. Therefore, Avista will not pursue
this resource expansion option at this time. If Long Lake expansion clearly
qualifies as a qualifying future resource, Avista may include it as a new resource
option in the future.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Avista Corp 2021 Electric IRP 14-5
 Avista identifies long duration pumped hydro storage as the capacity resource to meet future
long duration deficits. Avista will continue engaging with pumped hydro developers
regarding this resource type. Avista will investigate the potential for pumped hydro in or near
its service territory for long-term potential. This Action Item will continue through future IRPs
and TAC updates will be provided as new information is available.

The Company met with developers of regional pumped hydro projects on multiple
occasions. The 2021 IRP resource options include the most viable pumped hydro
options along with the costs and timelines as informed by these discussions. Long
duration pumped hydro is likely available later than the timelines used in the 2020
IRP and at higher costs. Although other shorter duration pumped hydro projects
are expected to be feasible to meet the capacity needs of the Company, these
projects will be further evaluated to determine if they are economic in a future
RFP process.

 The resource analysis identifies a natural gas CT to replace resource deficits if pumped
hydro is not feasible to meet the 2026 shortfall. Avista will conduct transmission and air
permitting studies to prepare for this contingency. Avista expects this process to take at
least two years.

Avista is currently investigating the transmission availability for natural gas-fired
CT and/or storage resource options. It has filed an interconnect study request and
it is at queue number 109. Air permitting studies have not been initiated at this
time.

 Avista will consider releasing a renewables RFP in the second quarter of 2020 for new
resources meeting the CETA requirements. Projects are preferred to be online by 2022 and
2023, but other start dates may be acceptable depending on cost effectiveness and other
considerations, including final CETA rule making requirements.

Avista issued an RFP on June 26, 2020 and concluded the process in October
2020. It is currently negotiating with short listed bidders. Any contracts signed
may alter the near-term results of the PRS and the updated PRS will be made
available after this IRP is filed.

 To meet the January 2026 capacity shortfall and to validate Avista’s preferred choice of long
duration pumped hydro to meet this deficit, Avista may release a capacity RFP as early as
2021. Avista will evaluate the appropriate timing of this RFP in 2020. Potential projects will
need to have a clear ability to serve Avista’s customers during winter peaks. Avista
anticipates existing resources, DR, renewable, thermal, and storage resources to respond.

Avista is still committed to releasing a capacity RFP in the near future subject to
the adjusted needs resulting from the acquisition from the 2020 Renewable RFP.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Avista Corp 2021 Electric IRP 14-6
 This IRP forecasts the Northeast CT will retire in 2035. Avista will continue to evaluate this
retirement date as it operates the facility and will provide the TAC with additional analysis
and information regarding the preferred retirement date.

Avista is maintaining the 2035 retirement date for the 2021 IRP. In addition to
retiring the Northeast CT, the Company’s engineering department has also
identified Boulder Park to likely retire by 2040.

 This IRP’s economic analysis determines Colstrip is best to shut down after 2025 compared
to alternative scenarios, such as a 2035 closure or operating a single unit through 2035. As
discussed in Chapter 12 – Portfolio Scenarios, the inclusion or exclusion of the social cost
of carbon regarding Colstrip does not change the economically optimal closure date. Avista
will continue evaluating this analysis and work with the other owners for the best course of
action to meet state objectives and the needs of all of Avista’s customers.

Avista’s analysis for the 2021 IRP is consistent with the 2020 IRP analysis.
Although the 2021 IRP indicates earlier removal than the 2020 IRP. The IRP
analysis is consistent with the plant’s exit from the Company’s resource portfolio
by the end of 2025, if not sooner, provided agreement can be reached with the
owners of Units 3 and 4.

Analytical and Process Action Items
 Avista will continue to study the costs of intermittent resources and understand the financial
benefits and capability of resources such as storage, natural gas-fired peakers and
hydroelectric resources to meet the intermittent characteristics of variable resources.
Studies will continue when sub-hourly modeling is functional in Avista’s ADSS software.
Avista’s timeline for this analysis is to be completed in 2021.

As discussed in the response to the 2017 IRP, Avista is still developing new
assumptions for valuing the sub-hourly costs and benefits of resources. Avista is
optimistic it will have updated analysis completed in time for inclusion in the 2023
IRP. A public process to evaluate these costs will begin in the second quarter of
2021

 Avista intends to include greenhouse gas emissions from resource construction,
manufacturing and operations where available. This research will begin in 2020 and will be
shared with the TAC members at a future meeting. Avista prefers this to be a collaborative
effort with the TAC members as there is clearly no accepted standard for this area of
research.

Avista included estimates of these emissions in its resource portfolio optimization
using data from the National Renewable Energy Lab (NREL). A resources option
spreadsheet including these emissions estimates was provided to the TAC
members and is as also available on the Company’s IRP website and Appendix
I. Further, Avista included these assumptions with its PRiSM model that is
available for review on the Company’s IRP website and Appendix I.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Avista Corp 2021 Electric IRP 14-7
 The time and resource commitment to produce the electric market price forecast is extensive
and difficult to complete internally. To make the best use of staff time and customer’s
resources, Avista will investigate early in 2020 whether using a third-party forecast, along
with an internally developed dispatch model, is a better approach to inform the resource
planning effort.

Avista used an internally developed market price forecast for the 2021 IRP. While
Avista has concerns with continued staffing for this function, it did not have time
to introduce a new process or partner between the 2020 and 2021 IRP filing
requirements and will reevaluate this need for the 2023 IRP.

 Washington State will issue rules for CETA and IRP planning over the next two years. Avista
will be an active participant in this rulemaking process. The timeline is 2020-2023.

Avista participated in both Commerce and Washington Utility and Transportation
Commission processes for CETA rulemaking and has implemented guidance for
developing the 2021 IRP from these processes as they became available.

 Avista will continue to support and participate in regional resource adequacy discussions
and market developments by the Northwest Power Pool and the CAISO respectively. Avista
will report back to the TAC when further information is available.

Avista actively participates in the regional resource adequacy effort including both
the trial program over the summer of 2020 and the development of a future
program. Further, it has conducted a scenario analysis in this IRP to identify the
benefits of this future program. The Company is committed to participating in this
regional program if there is support to implement it.

2021 IRP Action Items
Due to the short period between the 2020 IRP and this IRP, the Company considers all
incomplete Action Items from the 2020 IRP to continue as Action Items for this IRP. In addition
to the 2020 IRP Action Items that are still in process, the Company identified the following items
for the 2023 IRP.

 Investigate and potentially hire a consultant to develop both a hydro and load forecast to
include a shift in climate in the Inland Northwest. This analysis would include a range in new
hydro conditions and temperatures so the Company can utilize the new forecast for resource
adequacy planning and baseline planning.

 Investigate streamlining the IRP modeling process to integrate the resource dispatch,
resource selection and reliability verification functions.

 Study options for the Kettle Falls CT regarding potential reductions of the natural gas supply
in winter months. The Company will investigate alternatives for this resource including fuel
storage, retirement or relocation of the asset.
 Determine how to best implement the Washington Commission’s strong encouragement
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Chapter 14: Action Items

Avista Corp 2021 Electric IRP 14-8
under WAC 480-100-620 (3) regarding distribution energy resource planning as a separate
process or in conjunction with the 2025 IRP.

 Form an Equity Advisory Group to ensure a reduction in burdens to vulnerable populations
and highly impacted communities and to ensure benefits are equitably distributed in the
transition to clean energy in the state of Washington. This group will provide guidance to the
IRP process on ways to achieve these outcomes.

 Avista will conduct an existing resource market potential to estimate the amount and timing
of existing resources available through 2045.

 Conduct further peak credit analysis to understand the reliability benefits of all resources
including demand response options with different duration and call options of the wide range
of DR program options.

 Avista will partner with a third-party consultant to identify non-energy impacts that have not
historically been quantified for both energy efficiency and supply side resources.

 Formalize the process for public to submit IRP-related comments and questions and for
Avista to share responses to those requests.

 Develop a transparent methodology to include pricing data and consider available options
for new renewable generation and energy storage options.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 309 of 317
Chapter 15: Clean Energy Action Plan

Avista Corp 2021 Electric IRP 15-1
15. Washington Clean Energy Action Plan

On May 7, 2019, the Clean Energy Transformation Act (CETA) was signed into law committing
Washington to an electricity supply free of greenhouse gas emissions by 2045. Consequently,
each utility must incorporate the social cost of greenhouse gas emissions as a cost adder for
all relevant inputs when developing IRPs, Clean Energy Action Plans (CEAP) and evaluating
and selecting resource options. RCW 19.280.030 states that for an Investor-Owned Utility, the
CEAP must (a) identify and be informed by the utility’s ten-year cost-effective conservation
potential assessment; (b) if applicable, establish a resource adequacy requirement; (c) identify
the potential cost-effective demand response and load management programs that may be
acquired; (d) identify renewable resources, non-emitting electric generation and distributed
energy resources that may be acquired and evaluate how each identified resource may be
expected to contribute to meeting the utility’s resource adequacy requirement; (e) identify any
need to develop new, or expand or upgrade existing bulk transmission and distribution facilities;
and (f) identify the nature and possible extent to which the utility may need to rely on alternative
compliance options, if appropriate.

Avista’s 10-year CEAP is a lowest reasonable cost plan of resource acquisition given societal
cost, clean energy and reliability requirements. Avista developed this CEAP in conjunction with
its Technical Advisory Committee with the intent to meet the capacity, energy and clean energy
needs of both Idaho and Washington. The resources described in this plan are specific to the
Washington portion of Avista’s system needs in compliance with CETA. The discussion of the
plan below describes the important considerations as required by the WUTC. Details regarding
the methodology and assumptions regarding this plan are found within the chapters of the 2021
IRP. This CEAP will be the basis for the upcoming 2021 Clean Energy Implementation Plan
(CEIP).

Table 15.1 illustrates annual capacity additions of all planned resources, including demand
response and energy efficiency, for 2022 through 2031.

Energy Efficiency Savings
Avista plans to acquire 508 GWh of cumulative energy efficiency over the next 10 years based
on this IRP analysis. This represents 61.3 aMW when accounting for transmission and
distribution line loses. These programs reduce winter peak loads by 64.3 MW and summer peak
loads by 69.5 MW. Information on energy efficiency targets, and detailed results, are available
in IRP chapters 5 and 11, Energy Efficiency and the Preferred Resource Strategy respectively.
Figure 15.1 illustrates the energy efficiency selected for the 2021 PRS as well as the 10-year
pro rata share of both annual and cumulative efficiency. For more information on the biennial
conservation target and the EIA penalty threshold see Table 5.2 in Chapter 5.

Avista will file an amended Clean Energy Action Plan with the Washington Utility and
Transportation Commission after any resource acquisition is complete from the 2020
Renewable RFP. No contracts were signed from the 2020 RFP in time to be included in this
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Chapter 15: Clean Energy Action Plan

Avista Corp 2021 Electric IRP 15-2
Table 15.1: Washington Annual Capacity by Resource Type

2022 2023 2024 2025 2026 2027 2028 2029 2030 2031
Supply Resources (MW)
Wind 0 100 100 0 0 0 100 0 0 0
Kettle Falls GS upgrade 0 0 0 0 7.9 0 0 0 0 0
Natural Gas CT 0 0 0 0 0 82.9 0 0 0 0
NW Hydro Slice 0 0 0 0 0 0 0 0 0 75
Total Resources 0 100 100 0 7.9 82.9 100 0 0 75

Demand Response (MW)
Variable Peak Pricing 0 0 1 2.1 4.2 1.3 0.6 -0.1 -0.1 -0.1
Time of Use Rates 0 0 0.3 0.7 1.0 0.9 0.3 0 0 0
Large C&I 0 0 0 0 0 25.0 0 0 0 0
DLC Smart Thermostats 0 0 0 0 0 0 0 0 0 0.6
Total Demand Response 0 0 1.3 2.8 5.2 27.2 0.9 -0.1 -0.1 0.5

Energy Efficiency
Energy Savings (GWh)1 33.5 39.6 43.9 52.1 58.3 62.9 65.5 64.0 61.2 56.1
Winter Peak Reduction 3.6 4.4 5.1 6.1 7.0 7.8 8.1 8.0 7.5 6.6
Summer Peak Reduction 4.5 5.3 5.9 7.0 7.5 8.1 8.3 8.1 8.1 6.8

Total MW2 3.6 104.4 106.4 8.9 20.2 117.9 109.0 7.9 7.3 82.0

Figure 15.1: Washington 10-year Energy Efficiency Target

Resource Adequacy
Avista must ensure its resources are adequate to serve its customers. Because of the benefits
of regional coordination, Avista is participating in the development of a potential regional
resource adequacy program. The Company’s participation in regional resource adequacy
efforts is important because the choices of other utilities affect the amount of resources that

1 Includes estimated line losses.
2 Uses winter peak savings for energy efficiency.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 311 of 317
Chapter 15: Clean Energy Action Plan

Avista Corp 2021 Electric IRP 15-3
must be constructed. Avista currently targets a 16 percent planning margin to meet winter
peaks, and 7 percent planning margin for summer peaks. This is in addition to meeting
operating reserves and regulation requirements. Avista estimates participation in a resource
adequacy program may reduce its needs for new capacity by up to 70 MW in 2031 based on
the current draft program design. These savings will potentially allow the utility to require lower
future resource acquisitions if the program is successfully developed and implemented.

Avista’s 2021 IRP calls for 83 MW of natural gas-fired capacity for Washington customers by
November 1, 2026, replacing the Lancaster PPA, to maintain reliability targets for Washington
customers during peak load hours however, a total of 211 MW is needed for all of Avista’s
customers. A future RFP may identify a lower cost clean resource to meet this reliability
shortfall, but the current IRP modeling results selected a natural gas-fired resource in 2026.

Demand Response and Load Management Programs
Avista does not have any demand response or load management programs today, but this
CEAP identifies new programs with the potential to reduce load by 37.6 MW by 2031. Load
management programs are projected to begin in 2024 with time of use and variable peak pricing
opt-in programs. Savings are estimated to be 12 MW by 2031. A 25 MW large commercial
customer program offering is selected before the Lancaster PPA ends in 2026. Another
program, starting in 2031, encourages the adoption of smart thermostats to control heating and
cooling load. The program expects to achieve 0.6 MW of savings in the first year and grow to
over 6 MW by 2045. Future all-source RFPs may find additional opportunities from demand
response aggregators or others.

Table 15.2: Demand Response and Load Management Programs

Program Washington
Time of Use Rates 3.1 MW (2024)
Variable Peak Pricing 8.9 MW (2024)
Large C&I Program 25.0 MW (2027)
DLC Smart Thermostats 0.6 MW (2031)
Total 37.6 MW (2031 Total)

Planned Clean Energy Acquisitions
Avista developed CEAP targets to ensure 100 percent of Washington retail sales by 2030 are
served with clean energy options including up to 20 percent from offsets such as RECs. Table
15.3 outlines the requirements and projected new resources to meet the goals. The 2021 IRP
identifies a need for 180 aMW of clean energy by 20313 along with 41 aMW of clean energy
purchases from Avista’s Idaho customers and 20 aMW of RECs from Idaho customers under
median hydro conditions. Depending on the determination of the WUTC’s decision regarding
compliance with the 100 percent goal, Avista may need additional clean energy and/or RECs if
renewable and non-emitting energy must be delivered to customers instantaneously. Chapter
12 – Portfolio Scenarios of the 2021 IRP outlines the cost and energy acquisition impacts of

3 The owned hydro energy forecast includes Washington customers’ share of additional energy from an upgrade
to the Post Falls hydro facility.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 312 of 317
Chapter 15: Clean Energy Action Plan

Avista Corp 2021 Electric IRP 15-4
this scenario.
The new resources identified to meet CETA include 300 MW (144 aMW) of Montana Wind, 5
aMW from a 12 MW upgrade to the Kettle Falls Generating Station in 2026 and 31 aMW from
renewing a 75 MW long-term hydro purchase power agreement in 2031. Avista’s Washington
customers may need to rely on the purchase of additional Idaho-shares of hydro energy in years
of poor water or wind output.

Avista does not anticipate pursuing any transformational energy projects at this time. If CETA
rule adoptions change from our current understanding of the law, the Company will revisit the
matter. Figure 15.2 summarizes the annual clean energy serving Washington each year and
by resource type in gigawatt-hours. The 10-year cumulative summary of clean energy is split
by resource type in Figure 15 in gigawatt-hours.

Table 15.3: 2022-2031 Washington Clean Energy Targets (aMW)

2022 2023 2024 2025 2026 2027 2028 2029 2030 2031
Retail Sales 647 650 651 655 657 658 658 661 662 663
PURPA 22 22 22 22 22 22 22 22 22 22
Solar Select 6 6 6 6 6 6 0 0 0 0
Net Requirement 619 623 624 628 629 631 636 640 641 642

Target Clean % 80 80 85 85 90 90 95 95 100 100
Clean Energy Goal 496 498 530 534 567 568 604 608 641 642

Owned Hydro 292 288 288 285 292 289 292 289 291 291
Contract Hydro 96 95 65 66 65 64 63 58 59 23
Kettle Falls 24 23 23 21 23 21 22 20 21 19
Palouse Wind 24 24 24 24 24 24 24 24 24 24
Rattlesnake Flat Wind 36 36 36 36 36 36 36 36 36 36
Adams Neilson Solar 0 0 0 0 0 0 6 6 6 6
Available Resources 473 466 436 431 439 434 441 433 436 399

Shortfall 23 33 94 103 127 134 163 174 204 242

Resource Forecast
Montana Wind 0 48 96 96 96 96 144 144 144 144
Kettle Falls Upgrade 0 0 0 0 6 6 6 6 5 5
Regional Hydro 0 0 0 0 0 0 0 0 0 31
ID AVA Ren. Purchase 23 0 0 7 25 32 13 25 42 41
ID AVA Hydro Purchase 0 0 0 0 0 0 0 0 13 21
Total Energy/RECs 23 48 96 103 127 134 163 175 204 242

Net Position 0 15 2 0 0 0 0 1 0 0

Total Clean Resource 23 48 96 103 127 134 163 175 191 180

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Chapter 15: Clean Energy Action Plan

Avista Corp 2021 Electric IRP 15-5
Figure 15.2: Washington Annual Clean Energy Acquisition

Figure 15.3: Cumulative Clean Energy Acquisition for Washington

2022 2023 2024 2025 2026 2027 2028 2029 2030 2031
Hydro Transfer - - - - - - - - 114 184
Wind/Bio. Transfer 201 - - 61 219 280 114 219 368 359
Solar - - - - - - 53 53 53 53
Wind 526 946 1,367 1,367 1,367 1,367 1,787 1,787 1,787 1,787
Biomass 210 201 201 184 254 237 245 228 228 210
Hydro 3,399 3,355 3,092 3,075 3,127 3,092 3,110 3,040 3,066 3,022
-
1,000
2,000
3,000
4,000
5,000
6,000
Gi
g
a
w
a
t
t

H
o
u
r
s
Hydro, 31,378
Biomass, 2,199
Wind, 14,086
Solar, 210
Wind/Bio. Transfer,
1,822
Hydro Transfer,
298
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Chapter 15: Clean Energy Action Plan

Avista Corp 2021 Electric IRP 15-6
Transmission & Distribution Improvements
Avista’s resource acquisition plan does not include significant transmission or distribution
improvements as acquired resources are likely to be off system or utilize existing transmission
assets and not require significant new transmission investment. Avista plans future
transmission investment following its 10-year plan described in Appendix G.

This IRP resulted in two interconnection requests to Avista’s transmission department to
evaluate future resource opportunities. The first is up to 200 MW in the Rathdrum area and the
second is to integrate the additional capacity at Kettle Falls for the upgrade opportunity. So far,
the Kettle Falls interconnection request does not require any significant improvements.
Rathdrum area results will not be available until later in 2021 after the publication of this IRP.

Avista continues to upgrade its distribution system as customer load grows. Avista conducted
a review of potential resource acquisitions that could defer distribution investments, but none
were selected in this IRP based on economic analysis of the alternatives. Avista will begin
designing a public process for distribution planning in 2021.

Energy Equity
Avista is developing a plan to ensure an equitable distribution of benefits and reduced burdens
on highly impacted communities and vulnerable populations through the IRP process. At the
time of drafting this plan, the state had not yet defined the highly impacted communities nor
provided guidance on acceptable cost premiums associated with an energy equity plan. Even
so, Avista began development of a methodology to identify vulnerable populations in 2020; but,
Avista will not finalize these populations groups until formation of its Equity Advisory Group
(EAG) in 2021. The EAG will guide the determination of these communities as well as assist in
designing the outreach and engagement that will be used to distinguish and prioritize indicators
and solutions. Avista recently committed to an energy efficiency program pilot focused on
vulnerable populations starting in 2021. Options on how to design and implement a program to
meet this commitment to help with the identification of any barriers or missing data to make
sure that these groups are receiving their fair share of energy and non-energy benefits continue
to be assessed.

This IRP includes analytical enhancements to its energy efficiency cost effectiveness test to
include non-energy benefits. These enhancements should ultimately benefit vulnerable
communities. Avista also includes provisions in its energy acquisition process to prioritize
projects that may improve resiliency and increase energy security in these communities. The
priority evaluation also includes preference to renewable projects located in vulnerable
population areas to further develop those economies. The plan does not include new generation
facilities in Washington4 except for an upgrade to the Kettle Falls wood-fired facility5.

4 A future request for proposals of renewable energy may yield local resources more beneficial than those
identified in this plan.
5 The Kettle Falls plant is not located in a vulnerable populated area.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1, Page 315 of 317
Chapter 15: Clean Energy Action Plan

Avista Corp 2021 Electric IRP 15-7
Cost Analysis
The 2021 IRP includes an analysis comparing the cost of the PRS to a baseline portfolio without
CETA clean energy requirements. This modeling exercise determines whether alterative
compliance mechanisms such as the 2 percent cost cap will be required. For the first two of the
four-year compliance periods under CETA, Avista expects to be under the cap by $64 and $61
million, respectively, absent any future equity-related program costs. Yet Avista found the
simple average rate increase over the first four-year period is actually 2.5 percent as shown in
Table 15.4. Table 15.5 shows the plan is also under the cost cap by $61 million over the second
four-year compliance period. The final two years of the 10-year plan are not shown as they are
part of a four-year period extending beyond this CEAP timeline. Those costs are also expected
to remain under the cost cap.

Table 15.4: 2022-2024 Washington Cost Cap Analysis (millions $)

2021 2022 2023 2024 2025 Total
Revenue Requirement w/ SCC 651 651 669 700 705
Baseline 650 657 672 678
Annual Delta 1 11 28 27 67
Four Year Max Spending

Table 15.5: 2025-2028 Washington Cost Cap Analysis (millions $)

2024 2025 2026 2027 2028 Total
Revenue Requirement w/ SCC 705 714 718 744 755
Baseline 688 709 721 731
Annual Delta 26 9 23 23 81
Four Year Max Spending 36 36 36 36 143
Comparison vs Annualized Cost Cap (10) (27) (13) (12) (61)

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Chapter 15: Clean Energy Action Plan

Avista Corp 2021 Electric IRP 15-8

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2021 Electric
Integrated Resource Plan
Appendices
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Schedule 1a, Page 1 of 1105
2021 Electric IRP Appendices
Table of Contents
Appendix A – 2021 IRP Technical Advisory Committee Presentations & Meeting Notes
Technical Advisory Committee Meeting 1 Presentations (Page 2)
Technical Advisory Committee Meeting 1 Minutes (Page 84)
Technical Advisory Committee Meeting 2 (Page 97)
Technical Advisory Committee Meeting 2 Minutes (Page 200)
Technical Advisory Committee Meeting 2.5 (Page 215)
Technical Advisory Committee Meeting 2.5 Minutes (Page 261)
Technical Advisory Committee Meeting 3 (Page 270)
Technical Advisory Committee Meeting 3 Minutes (Page 421)
Technical Advisory Committee Meeting 4 (Page 432)
Technical Advisory Committee Meeting 4 Minutes (Page 517)
Technical Advisory Committee Meeting 4.5 (Page 523)
Technical Advisory Committee Meeting 4.5 Minutes (Page 561)
Technical Advisory Committee Meeting 5 (Page 565)
Technical Advisory Committee Meeting 5 Minutes (Page 637)
Public Participation Meeting 6 (Page 645)

Appendix B – 2021 Electric IRP Work Plan (Page 683)

Appendix C – Public Participation Comments (Page 689)

Appendix D – Confidential Historical Generation Operation Data (Page 833)

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Appendix E – AEG Conservation & Demand Response Potential Assessment (Page
835)

Appendix F – Avoided Cost Calculations (Page 979)

Appendix G – Transmission 10- year plan (2020) and 2019-2020 Avista System
Assessment (Page 985)

Appendix H – New Resource Table for Transmission (Page 1065)

Appendix I – Publicly Available Inputs and Models (Page 1067)

Appendix J – Confidential Inputs and Models (Page 1091)

Appendix K – Load Forecast Supplement (Page 1095)

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 3 of 1105
2021 Electric Integrated
Resource Plan
Appendix A – 2021 Technical
Advisory Committee
Presentations and Meeting
Minutes
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 4 of 1105
2021 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 1 Agenda
Thursday, June 18, 2020
Virtual Meeting
Topic Time Staff
Introductions 9:00
TAC Expectations and Process Overview 9:05 Lyons
2020 IRP Acknowledgement 9:45 Lyons
Break 10:15
CETA Rulemaking Update 10:30 Bonfield
Modeling Process Overview 11:00 Gall
Lunch 12:00
Generation Options 1:00 Hermanson
Break 2:00
Highly Impacted Communities Discussion 2:15 Gall
Adjourn 3:30
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 5 of 1105
2021 Electric IRP
TAC Expectations and Process Overview
John Lyons, Ph.D.
First Technical Advisory Committee Meeting
June 18, 2020
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Schedule 1a, Page 6 of 1105
Updated Meeting Guidelines
•IRP team is working remotely, still available by email and
phone for questions and comments
•Some processes are taking longer remotely
•Adding stakeholder feedback form to the IRP website –
posted with responses
•Researching best way to share other IRP data
•Virtual IRP meetings on Skype until back in the office
and able to hold large group meetings
•TAC presentations and notes will still be posted on IRP
page
2
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Virtual TAC Meeting Reminders
•Please mute mics unless speaking or asking a question
•Use the Skype chat box to write out or let us know you
have a question or comment
•Respect the pause
•Please try not to speak over the presenter or a speaker
who is voicing a question or thought
•Remember to state your name before commenting for
the note taker
•This is a public advisory meeting –presentations and
comments will be recorded and documented
3
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Schedule 1a, Page 8 of 1105
Integrated Resource Planning
The Integrated Resource Plan (IRP):
•Required by Idaho and Washington* every other year
–Covering timing of 2020 and 2021 IRPs in next presentation
•Guides resource strategy over the next twenty + years
•Current and projected load & resource position
•Resource strategies under different future policies
–Generation resource choices
–Conservation / demand response
–Transmission and distribution integration
–Avoided costs
•Market and portfolio scenarios for uncertain future
events and issues
4
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Schedule 1a, Page 9 of 1105
Technical Advisory Committee
•The public process piece of the IRP –input on what to study, how to
study, and review of assumptions and results
•Wide range of participants involved in all or parts of the process
–Ask questions
–Help with soliciting new members
•Open forum while balancing need to get through all of the topics
•Welcome requests for studies or different assumptions.
–Time or resources may limit the number or type of studies
–Earlier study requests allow us to be more accommodating
–August 1, 2020 is the study request deadline
•Planning team is available by email or phone for questions or
comments between the TAC meetings
5
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 10 of 1105
2021 Electric IRP TAC Schedule
•TAC 1: Thursday, June 18, 2020
•TAC 2: Thursday, August 6, 2020 (Joint with Natural Gas TAC)
•TAC 3: Tuesday, September 29, 2020
•TAC 4: Tuesday, November 17, 2020
•TAC 5: Thursday, January 21, 2021
•Public Outreach Meeting: February 2021
•TAC agendas, presentations and meeting minutes available at:
https://myavista.com/about-us/integrated-resource-planning
6
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Schedule 1a, Page 11 of 1105
2021 IRP Key Dates – Work Plan
•Identify Avista’s supply resource options –May 2020
•Finalize natural gas price forecast –June 2020
•Finalize demand response options –July 2020
•Finalize energy efficiency options –July 2020
•Update and finalize energy and peak forecast –July 2020
•Finalize electric price forecast –August 2020
•Transmission and distribution studies due –August 2020
•Determine portfolio and market future studies –August 2020
•Due date for TAC study requests –August 1, 2020
•Finalize PRiSM model assumptions –September 2020
•Simulate market scenarios in Aurora –September 2020
•Portfolio analysis and reliability analysis –October 2020
•Present portfolio analysis to TAC –November 2020
7
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 12 of 1105
2021 IRP Public Data Release Schedule
•Supply Side Resource Options –June 2020
•Conservation Potential Study Data –July 2020
•Demand Response Potential Study Data –July 2020
•Peak & energy Load Forecast –July 2020
•Wholesale Natural Gas Price Forecast –August 2020
•Wholesale Electric Price Forecast –September 2020
•Transmission Interconnect Costs –September 2020
•Existing Resource Data –September 2020
•Annual Capacity Needs Assessment –November 2020
8
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 13 of 1105
2021 IRP Key Document Dates
•Filed 2021 IRP Work Plan April 1, 2020
•Internal IRP draft released at Avista on December 4, 2020
•External draft released to the TAC on January 4, 2021
•Comments and edits from TAC due on March 1, 2021
•Final editing and printing –March 2020
•Final IRP submission to Commissions and TAC on April 1,
2021
9
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Schedule 1a, Page 14 of 1105
Today’s TAC Agenda
9:00 –Introductions
9:05 –TAC Expectations and Process Overview, Lyons
9:45 –IRP Acknowledgement, Lyons
10:15 –Break
10:30 –CETA Rulemaking Update, Bonfield
11:00 –Modeling Process Overview, Gall
Noon –Lunch
1:00 –Generation Options, Hermanson
2:00 –Break
2:15 –Highly Impacted Communities Discussion, Gall
3:30 –Adjourn
10
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Schedule 1a, Page 15 of 1105
2020 Electric IRP
Acknowledgement Update
John Lyons, Ph.D.
First Technical Advisory Committee Meeting
June 18, 2020
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Schedule 1a, Page 16 of 1105
Normal Acknowledgement Process
•Avista’s electric IRP previously submitted to
Idaho and Washington Commissions every other
August in odd years
•Commissions set periods for public comments
and meetings
•Acknowledgements issued detailing IRP
outcomes, comments and expectations for the
next IRP
•Normally, we provide details about the
acknowledgments in this meeting
2
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Schedule 1a, Page 17 of 1105
How The IRP Changed
•Expectations and passage of the Clean Energy
Transformation Act (CETA) in 2019 led to six
month IRP extensions
–February 28, 2020 in Idaho in AVU-E-19-01 Order
No. 34312
–Washington further extended until April 1, 2021
–Two IRPs in two years
3
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Schedule 1a, Page 18 of 1105
Idaho
•AVU-E-19-01 (https://puc.idaho.gov/case/Details/3633)
•Requests from the Mayor of Sandpoint, Idaho, Idaho
Forest Group, Idaho Conservation League and
Embodied Virtue for the IPUC to hold a public hearing in
North Idaho
•IPUC set a deadline of August 19, 2020 for public
comments about the IRP with Avista replies due
September 2, 2020
•Will update the TAC on future comments and
acknowledgement
•Ongoing discussions with Commission Staff and ICL
concerning several aspects about modeling, Colstrip and
the impact of CETA on Idaho customers
4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 19 of 1105
Washington
•Submitted the 2020 IRP to the Washington UTC
•Washington Commission temporarily suspended issuing IRP
acknowledgement letters in UE-180738 Order 02 until
December 31, 2020
•Progress filed report filed on October 25, 2019 to
accommodate CETA rulemaking
–Commission cannot legally acknowledge an IRP without meeting
certain CETA guidelines which still need to have rulemaking
completed
•Next draft electric IRP must be submitted by January 4, 2021
and final 2021 electric IRP must be submitted by April 1,
2021
•No specific requirements or expectations from an
acknowledgment letter from the 2020 IRP
5
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Schedule 1a, Page 20 of 1105
Washington
•2021 IRP expectations are going to focus on the results of
CETA rulemaking
Some Washington UTC requests on the work plan include:
•Provide opportunity for stakeholder input on the CPA before
finalizing the options
•How equity issues required under CETA will be incorporated in the
IRP (TAC 1 and TAC 2)
•Extending participation beyond the TAC through some form of public
outreach at a higher level before the end of the IRP process
(February 2021)
•Concerns over draft CEIP being included in the IRP
•Provide a general outline of when Avista will provide data or files for
stakeholder review and comment deadlines (first presentation today)
6
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 21 of 1105
Clean Energy Transformation Act (CETA)
Overview and Implementation Status
Shawn Bonfield, Sr. Manager Regulatory Policy & Strategy
First Technical Advisory Committee Meeting
June 18, 2020
DRAFT
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 22 of 1105
CETA: A Brief Overview
•Senate Bill 5116 –passed by legislature in 2019
•Applies to all electric utilities in WA and sets specific milestones to
reach required 100% clean electric supply
•By 2025 –eliminate coal-fired resources from serving WA customers
•By 2030 –electric supply must be greenhouse gas neutral,
•By 2045 –electric supply must be 100% renewable or be generated
from zero-carbon resources
Source: WA Department of Commerce2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 23 of 1105
CETA: Additional Details
Utilities must:
–Ensure the equitable distribution of energy and nonenergy
benefits and reduction of burdens to vulnerable populations and
highly impacted communities
–Ensure long-term and short-term public health and
environmental benefits and reduction of costs and risks
–Ensure energy security and resiliency
–Make progress toward and meet the standards of the law:
•While maintaining and protecting the safety, reliable operation, and
balancing of the electric system
•At the lowest reasonable cost
3
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 24 of 1105
Source: WA
Department of
Commerce
4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 25 of 1105
Source: WA Department of Commerce
5
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 26 of 1105
UTC CETA Implementation Plan
UE-190485 (Closed)
•Phase 0 –overall implementation plan
–Process timeline and scope of issues
•Phase I -August 2019 to January 1, 2021
–Elements that must be complete by January 1, 2021 as required by
Section 10 of SB 5116
–Publish the social cost of carbon on UTC’s website by September 15,
2019
–Initiate dockets for various rulemakings relating to CETA implementation
•Phase II –January 1, 2021 to June 30, 2022
–Rulemakings with deadlines after January 1, 2021
–Amend IRP rules to incorporate Cumulative Impact Analysis
–Carbon and Electricity Markets Rulemaking
6
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 27 of 1105
Social Cost of Carbon
U-190730 (Closed)
•New section added to chapter 80.28 RCW, outlining cost
of greenhouse gas emissions resulting from the
generation of electricity and use of natural gas, the UTC
must adjust the social cost of carbon to reflect the effect of
inflation.
•Social Cost of Carbon published on UTC website in
September 2019:
–https://www.utc.wa.gov/regulatedIndustries/utilities/Pages/SocialC
ostofCarbon.aspx
7
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 28 of 1105
Energy Independence Act (EIA)
Rulemaking – UE-190652
•E2SSB 5116: Amending WAC 480-109, Energy Independence Act
(EIA) rules
a.Streamline E2SSB 5116 with EIA rules. (§10(3))
b.Discuss equitable distribution of benefits.
c.Discuss low-income definition, if needed. (§2(25))
d.Discuss energy assistance need definition, if needed. (§2(16))
e.Consider incorporating low-income energy efficiency target.
f.Incorporate updates to hydro eligibility and tracking. (§§28 and 29)
Status: Written comments due on draft rules July 6th. Rule adoption
hearing set for July 28th.
8
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 29 of 1105
Clean Energy Implementation Plan (CEIP)
Rulemaking UE-191023
•E2SSB 5116: New Chapter, Clean Energy Implementation Plans
(CEIPs)
a.Provide guidelines for Clean Energy Implementation Plans. (§6)
b.Discuss equitable distribution of benefits. (§4(8))
c.Develop incremental cost methodology at the beginning of the
rulemaking. (§6)
d.Address reporting and compliance, and the penalty process. (§9(1)(a))
Status: First draft of rules released May 5, 2020 with comments due June
2, 2020. Second set of draft rules to be released in July timeframe.
9
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 30 of 1105
Electric IRP Updates Rulemaking
UE-190698
•E2SSB 5116 and EHB 1126: Amending WAC 480-100-238, Electric Integrated
Resource Plans (IRP)
a.Update inputs to IRPs (e.g., hydro eligibility and tracking;4 resource adequacy; distributed energy resources
principles from EHB 1126; and demand response).
b.Update structure of IRPs.
c.Update public involvement process.
d.Update outputs of IRP Clean Energy Action Plans. (§14(2))
e.Incorporate the social cost of carbon into IRPs. (§14(3)(a))
f.Refine the development of avoided costs to reflect E2SSB 5116 and social cost of carbon.
g.Develop resource value test based on review of E2SSB 5116 and social cost of carbon.
h.Discuss equitable distribution of benefits. (§4(8))
i.Discuss assessment informed by cumulative impact analysis, as needed. (§14(1)(k))
j.Amend IRP rules to incorporate the Cumulative Impact Analysis complete by Department of Health
workgroup. (ch. 288, §14(11))
k.Incorporate distributed energy resources elements from EHB 1126. (ch. 205, §1)
Status: Development and preparation of draft rules ongoing.
10
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 31 of 1105
Purchase of Electricity (PoE) Rulemaking
UE-190837
•E2SSB 5116: Amending WAC 480-107, Resource Acquisition
(Requests for Proposals, or RFP)
a.Incorporate existing work on RFPs from Docket U-161024.
b.Ensure that the E2SSB 5116 standard is met in construction and
acquisition of property and the provision of electric service. (§5)
c.Incorporate resource adequacy considerations. (§6(2)(a)(iv))
d.Discuss equitable distribution of benefits. (§6(1)(c)(iii))
Status: Second round of draft rules issued June 1, 2020 with
comments due June 29, 2020.
11
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 32 of 1105
Carbon & Electricity Markets Workgroup
UE-190760
•E2SSB 5116: With the Department of Commerce, initiate
a Carbon and Electricity Markets Workgroup for regular
discussions to inform Phase II rulemaking.
•Define requirements for load met with market purchases.
(ch. 288, §13)
Status: Workgroup to hold four educational workshops
to set a base of understanding. Second workshop
scheduled for June 10, 2020. Public work sessions to
begin in Fall 2020 with rulemaking complete June 30,
2021.
12
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 33 of 1105
Department of Commerce Rulemakings
•Thermal Renewable Energy Credits –applies to all
utilities
•Reporting and demonstration of compliance –applies to
all utilities
•CEIP for consumer-owned utilities –ensure alignment
with UTC rules
•Cost methodology for rate impact –applies to all utilities
Rules effective January 1, 2021
13
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 34 of 1105
Department of Ecology Rulemakings
•Ecology is starting rulemaking for Chapter 173-444 WAC, Clean
Energy Transformation Rule to implement parts of the Clean Energy
Transformation Act assigned to Ecology. The rulemaking will:
–Establish a process to determine what types of energy transformation
projects may be eligible to meet the Clean Energy Transformation Act.
–Establish a process and requirements to develop standards,
methodologies, and procedures to evaluate energy transformation
projects.
–Provide greenhouse gas emission factors for electricity.
•Timeline
–Spring 2020 –develop and prepare rule language
–Summer 2020 –public hearing and comment
–December 2020 –adopt rule
–January 2021 –rule effective
14
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 35 of 1105
2021 Electric IRP
Modeling Process Overview
James Gall, IRP Manager
First Technical Advisory Committee Meeting
June 18, 2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 36 of 1105
IRP Planning Models
Aurora
PRiSM
“Reliability”
Model
PowerWorld Synergi
Load
Forecast
Resource
Options
Transmission & Distribution Models will be discussed in TAC 3
Discuss in TAC 2
Supply-side: Today
Demand Side: TAC 2
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 37 of 1105
Aurora
•Electric Market-Production Cost Model
•Developed by Energy Exemplar
•Industry standard and widely used in the Pacific Northwest
•Avista started using software for the 2003 IRP
•Simulates generation dispatch to meet load allowing for system
constraints
Inputs:
–Regional loads*
–Fuel prices*
–Fuel availability*
–Resources (availability*)
–New resources costs
–Transmission
–System Constraints
Outputs:
–Market prices
–Energy mix
–Transmission usage
–Emissions
–Power plant margins,
generation levels, fuel costs
–Avista’s variable power supply
costs
*Stochastic input
3
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 38 of 1105
Aurora Pricing Methodology
•Each area contains a load and
resources.
•Aurora dispatches resources to meet
the load for each hour.
•Resource dispatch is dependent on
fuel availability (wind, solar, hydro)
and economic dispatch of the
resource (fuel price).
•The model includes resource
outages for maintenance and forced
outage.
•For each location and hour, the
model estimate a wholesale electric
price using the marginal resource to
serve the load.
4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 39 of 1105
Stochastic vs. Deterministic Analysis
•Deterministic analysis forecasts for a specific set of inputs.
–Easier to understand
–Works great for sensitivity analysis of specific changes
•Stochastic analysis forecasts for a range of inputs.
–Range (or distribution) of results
–Works great to understand risks of the inputs with variation
•Avista uses mean value of stochastic analysis for its Expected
Case scenario.
5
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 40 of 1105
Aurora Model Assumptions
•Forecast will start with the 2020 IRP
–Uses latest available database from Energy Exemplar
•Proposed database changes
–Natural gas prices (TAC 2)
–Include new resource additions and announced retirements
–Include known state/province environmental laws; including adjustments for
oversupply events
–Review inputs for load and new resources options
•EV/rooftop solar forecast
•New resources cost
–Add proprietary Avista system information
–Add stochastic distribution of regional hydro, natural gas, wind, and loads
•Avista will discuss non-confidential modeling changes in TAC 3
•All other Aurora assumptions are default values
6
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 41 of 1105
Aurora Run Process
•Once inputs are finalized (July 2020)
•Run Long Term “LT” study to estimate new resource additions for the
full hourly study
•Test reliability under 500 simulations of varying hydro, load, forced
outage, and wind conditions for future year (i.e. 2035)
•Update LT study to reflect any “need” for new resources and validate
regional reliability
•Run deterministic study
•Run stochastic study (500 simulations, each hour for 2022-45)
•Run scenarios
7
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 42 of 1105
What Aurora Outputs are used?
•Resource dispatch for Avista existing resources and resource
options
–Estimate profitability of each supply and demand side resource
–Estimate dispatch for REC calculation for CETA
•Value the cost to serve Avista’s load
•Estimate the emissions associated with supply side and storage
resources
•Estimate regional emission rates for savings for energy efficiency
resources
•Gain understanding of the region market
•Data is used to populate PRiSM Model
8
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 43 of 1105
PRiSM- Preferred Resource Strategy
Model
Internally developed using Excel based linear/mixed integer program
model (What’s Best & Gurobi)
Selects new resources to meet Avista’s capacity, energy, and
renewable energy requirements
Outputs:
–Power supply costs (variable and fixed)
–Power supply costs variation
–New resource selection (generation/conservation)
–Emissions
–Capital requirements
9
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 44 of 1105
What’s new with PRiSM for this IRP
New resources may be added to either WA, ID, or combined
customer requirements.
Existing resources will be allocated to each state using the PT ratio
(~65% WA and ~35% ID).
States may sell RECs between states.
Washington’s former share of Colstrip units will be assigned to new
“shareholder” portfolio after 2025.
10
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 45 of 1105
Social Cost of Carbon (SCC)
•Social cost of carbon will be applied for new resource options for
Washington customers; including
–“Resulting” dispatch of natural gas resources from Aurora forecast of
future real-time operations.
–upstream emissions associated with natural gas drilling and
transportation used to run facility.
–manufacturing, construction, and operation of all resources (using NREL
study).
–storage and market resources will include estimate based on the
average emissions rate of the region.
–energy efficiency resources will use the hourly marginal emission rate of
the region and reduction.
–SCC will not be used for biomass/geothermal resources
•SSC prices will not be included for Idaho customers; although Avista
could study this as a scenario
11
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 46 of 1105
Social Cost of Carbon Prices
SCC (2007$)SCC (2019$)Nominal $
Social cost of carbon dioxide in 2007 dollars using the 2.5% discount rate, listed in table 2, technical support
document: Technical update of the social cost of carbon for regulatory impact analysis under Executive Order No.
12866, published by the interagency working group on social cost of greenhouse gases of the United States
government, August 2016.
Adjust to 2019$ using Bureau of Economics GDP
Adjust to Nominal $ using 2.11% annual inflation rate
Levelized Price: $114.63 per Metric Ton
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 47 of 1105
Issues not finalized
•Prices of REC transfer between states
–Avista acquires new qualifying resources to meet Washington’s portion
of the law, although it may transfer RECs between Idaho and
Washington for the 20% portion of CETA
•How to count REC’s toward meet the “80%” portion of CETA
–Must bundled RECs only qualify if meeting Avista WA state load each
hour?
–Serve any WA state load or any utility load?
–Avista needs clarification from WUTC
13
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 48 of 1105
What is Reliability Planning
•Estimate the probability of failure to serve all load
–Avista’s reliability target is 95% of all simulations serve 100% of load and reserve
requirments
•Model randomizes events
–Hydro, weather (load, wind, resource capacity), forced outages
•Typically large sample size 1,000 simulations
•Can be used to validate if a portfolio is reliable
–Estimate the required planning reserve margin (PRM)
–May be used to estimate peak credits for new resources (ELCC)
•Gold standard: regional wide program with enforced requirements to
each utility
–Set required methodology, planning margin, and resource contribution
based on regional model
14
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 49 of 1105
Reliability Modeling
•2020 IRP included ELCC analysis for a new resource alternatives
and Avista Preferred Resource Portfolio for the year 2030
•Avista sees areas to improve in reliability modeling
–Quantity of future years
–Create ELCC curve for new resources
–Study all portfolio’s reliability requirements
–Improve model speed
•Single year study takes 3 days
–Create dynamic capability with PRiSM
15
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 50 of 1105
Options to Address Reliability Modeling
Option Pros Cons
Continue using existing model
(ARAM-excel model with solver)
•Results reliable for Avista system
•Fully developed
•Potential for modest speed improvements
•Control intellectual property
•Slow
•Limited to two processes
•User data/knowledge intensive
Build custom professional software •Likely faster speed
•Reliable results
•Potential to integrate with PRiSM
•Time to implement
•Cost
Adapt Aurora •User knowledge
•Cost
•Flexibility
•Data management
•Parallel processing limit by machines
•Slow (cost to speed up-Gurobi)
•Hydro logic-results in higher LOLP
•May only work for LOLH
•Storage logic is slow
New Genesis Model
(Power Council)
•Regional standard
•Addresses regional market availability
issues
•Strong hydro logic
•New technology
•Regional focus
•Model in progress; not available for
this IRP
Purchase Software/Hire Consultant •Flexibility
•Data management
•Reliable results ?
•Cost
•Implementation time
•Risk
Regional Resource Adequacy Market •Clear requirements for load and resources
on a regional basis
•Best case scenario
•Market in development not ready for
this IRP
•May have to make estimates for
future years
16
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 51 of 1105
Reliability Next Steps
•Continue testing Aurora application with Gurobi to understand speed
improvements and result improvements
•If we use ARAM
–Remain with single year study (2030 or 2035)
–Use 2020 IRP ELCC estimates
–Estimate ELCC curves for key resources (wind/ storage)
–Conduct study for each portfolio-may result in different planning
margins
–Move to using RA logic for next IRP if a regional program is developed
•Aurora option may expand options to additional forecast years and
ELCC studies
•Update progress with TAC once solution is finalized
17
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 52 of 1105
Data Availability Proposal
•Aurora
–Model requires licensing agreement with Energy Exemplar
–Avista specific data is confidential
–Model results will be retained by Avista
–Avista will provide summary level results for all studies (i.e. regional prices, regional emissions, regional dispatch)
•PRiSM
–All files will be available, includes annual data for each of 500 simulations for Avista resources and load
–Requires What’s Best and Gurobi license to solve, but results are fully visible
•Load Forecast
–Models are confidential; models includes specific customer information and confidential data
–Monthly energy and peak data will be available by state, along with break down between new +/-loads (i.e. rooftop
solar, electric vehicles, and natural gas)
–Full discussion of process will be covered in TAC 2
•Resource Costs
–Supply-side resources spreadsheet will be available with all calculations
–Demand-side resources; measure list and costs will be public for energy efficiency and demand response.
•Transmission & Distribution
–All models and data are confidential
–Avista will provide cost and requirements for resource integration as provided in prior IRPs
–Full discussion of process will be covered in TAC 3
•Reliability Planning
–Availability will depend on modeling solution
–Results will be retained and available
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 53 of 1105
2021 Electric IRP
Generation Resource Options
Lori Hermanson, Senior Power Supply Analyst
First Technical Advisory Committee Meeting
June 18, 2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 54 of 1105
Overview & Considerations
•The assumptions discussed are “today’s” estimates –likely to be
periodically revised
•IRP supply-side resources are commercially available technologies with
potential for development within or near Avista service territory
•Resource costs vary depending on location, equipment, fuel prices and
ownership; while IRPs use point estimates, actual costs will be different.
•Certain resources will be modeled as purchase power agreements (PPA)
while others will be modeled as Avista “owned”. These assumptions do
not mean they are the only means of resource acquisition.
•No transmission or interconnection costs are included at this time.
•Natural gas prices are 2020 IRP prices and will be revised with the “final”
assumptions
•An Excel file will be distributed with all resources, assumptions and cost
calculations for TAC members to review and provide feedback.
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 55 of 1105
Outlook Since Last IRP
•Natural gas small CT –4.4%
•Natural gas CCCT -5.8%
•Solar –8%
•Wind –0.3%
•Lithium Ion Storage –8%
3
Gas turbines 2022 vs 2020; others are 2022 vs 2022
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 56 of 1105
Proposed Natural Gas Resource Options
Peakers
•Simple Cycle Combustion Turbine
(CT)
–Aero and frame units
–Smaller units 44 MW to 84 MW
•Hybrid CT
–92 MW
•Reciprocating Engines
–9 MW to 18 MW units with up
to 10 engines
Baseload
•Both modern and advanced
Combined Cycle CT (CCCT) will
be evaluated
–Smaller option 249 MW (3x2)
–Larger options 311 MW to 587
MW (1x1)
•Large 2x1 technology not modeled
Natural gas turbines are modeled using a 30-year life with Avista ownership
4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 57 of 1105
Renewable Resource Options
All Purchase Power Agreement (PPA) Options
Wind
•On-system wind (100 MW)
•Off-system wind (100 MW)
•Montana wind (100 MW)
•Offshore wind (100 MW)
–Share of a larger project
Solar
•Fixed PV Array (5 MW AC)
•On-System Single Axis
Tracking Array (100 MW AC)
•Off-system Single Axis
Tracking Array (100 MW AC)
located in southern PNW
•On-System Single Axis
Tracking Array (100 MW AC)
with 25 MW 4 hour lithium-ion
storage resource
•May model alternative solar
with smaller battery
configurations
5
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 58 of 1105
Other “Clean” Resource Options
•Geothermal (25 MW)
–Off-system PPA
•Biomass (25 MW)
–i.e. Kettle Falls 3 or other
•Nuclear (100 MW)
–Off-system PPA share of a mid-size facility
•Renewable Hydrogen
–Fuel Cell (25 MW)
–Natural Gas Turbine Retrofit
6
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 59 of 1105
Storage Technologies
Lithium-Ion
•Assumes: 88% round trip
efficiency (RTE), 10-year
operating life
•Assumes Avista ownership
•5 MW Distribution Level
–6 hours (30 MWh)
•25 MW Transmission Level
–4 hours (100 MWh)
–8 hours (200 MWh)
–16 hours (400 MWh)
Other Storage Options
•Assumes 20 to 30-year life and Avista
ownership
•25 MW Vanadium Flow (70% RTE)
–4 hours (100 MWh)
•25 MW Zinc Bromide Flow (67% RTE)
–4 hours (100 MWh)
•25 MW Liquid Air (60-70% RTE)
•100 MW Pumped Hydro
–Share of larger project
–PPA assumption
Updates to storage costs are
likely as additional information
becomes available7
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 60 of 1105
Resource Upgrades
•Rathdrum CT [natural gas peaker]
–5 MW by 2055 uprates
–24 MW add supplemental compression
–17 MW (summer), 0 MW (winter) Inlet Evaporation
•Kettle Falls [biomass]
–12 MW by repowering with larger turbine during replacement
•Long Lake 2nd Powerhouse [hydroelectric]
–68 MW, 12 aMW with additional powerhouse located at the
current “cutoff” dam
•Cabinet Gorge [hydroelectric]
–110 MW, 18 aMW using the “bypass” tunnels to capture runoff
spill
8
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 61 of 1105
Adv Small Frame CT
Frame/Aero Hybrid CT
Lg Recip
Sm Recip
Modern SmFrame CT
Aero CT
$0
$5
$10
$15
$20
$25
$30
$35
$40
$45
$50
$0 $50 $100 $150 $200 $250 $300
Fixed Cost 2022 $ per kW-yr at Busbar
Natural Gas Fixed & Variable Costs
9
Green: Reciprocating Engines
Blue: SCCT
Red: CCCT
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 62 of 1105
PPA Resource Cost Analysis
10 Prices include utility loading such as variability integration and revenue taxes
$0 $20 $40 $60 $80 $100 $120 $140 $160
On-System Wind
Off-System Wind
MT Wind
Off Shore Wind
On-System Solar
Southern NWSolar
Small Solar
Nuclear
Geothermal
2042
2032
2022
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 63 of 1105
Storage Costs
Capacity based cost analysis
11
$0 $200 $400 $600 $800
Distribution Scale 6hr Lithium-Ion
4hr Lithium-Ion
8hr Lithium-Ion
16hr Lithium-Ion
4 hr Vanadium Flow Battery
4 hr Zinc Bromide Flow Battery
Liquid Air
Pumped Hydro (16 hr/ 100 MW share)
$ per kW-Year
2042
2032
2022
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 64 of 1105
Storage Costs
Energy based cost analysis
12
$0 $20 $40 $60 $80 $100 $120
Distribution Scale 6hr Lithium-Ion
4hr Lithium-Ion
8hr Lithium-Ion
16hr Lithium-Ion
4 hr Vanadium Flow Battery
4 hr Zinc Bromide Flow Battery
Liquid Air
Pumped Hydro (16 hr/ 100 MW share)
$ per kWh-Yr
2042
2032
2022
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 65 of 1105
Rath Supp Compression
Rath CT 2055 Uprate
Rath CT Inlet Evap
KF Turbine Gen Update
LL 2nd
PowerhouseCG 2nd
Powerhouse
Biomass
$0
$10
$20
$30
$40
$50
$60
$0 $50 $100 $150 $200 $250 $300 $350
20
2
2

$

p
e
r

M
W
h
2022 $ per kW-yr at Busbar
Facility Upgrade Cost Analysis
13
Green: Biomass
Blue: Hydro
Red: Natural Gas
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 66 of 1105
Other Power Purchase Options
•Market Power Purchases
–Firm purchases
–Real-time
•Mid-Columbia Hydro
–Renegotiate slice contracts from Mid-C PUDs
•Acquire existing resources from IPPs
•Renegotiate Lancaster PPA
•BPA
–Block surplus contract: up to 7-year term at BPA “cost”
–NR Energy Sales: $78.94 MWh
–After 2028, other potential options when current Regional
Dialogue contracts expire
14
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 67 of 1105
Other Items for TAC Input
•Pumped hydro
–Model specific projects vs.
generic options
•Hydrogen Technologies
(still researching)
–Fuel cell
–Gas turbine retrofit
•Will consider other
resource options subject to
TAC input
14
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 68 of 1105
Review Excel Sheet
16
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 69 of 1105
2021 Electric IRP
Washington Vulnerable Populations &
Highly Impacted Communities
James Gall, IRP Manager
First Technical Advisory Committee Meeting
June 18, 2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 70 of 1105
CETA: Section 1
(6) The legislature recognizes and finds that the public interest
includes, but is not limited to:
•The equitable distribution of energy benefits and reduction of
burdens to vulnerable populations and highly impacted
communities;
•long-term and short-term public health, economic, and
environmental benefits and the reduction of costs and risks;
•and energy security and resiliency.
It is the intent of the legislature that in achieving this policy for
Washington, there should not be an increase in environmental health
impacts to highly impacted communities.
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 71 of 1105
Definitions
(23) "Highly impacted community" means a community designated by
the department of health based on cumulative impact analyses in
section 24 of this act or a community located in census tracts that are
fully or partially on "Indian country" as defined in 18 U.S.C. Sec. 1151
(40) "Vulnerable populations" means communities that experience a
disproportionate cumulative risk from environmental burdens due to:
(a) Adverse socioeconomic factors, including unemployment, high housing
and transportation costs relative to income, access to food and health
care, and linguistic isolation; and
(b) Sensitivity factors, such as low birth weight and higher rates of
hospitalization.
3
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 72 of 1105
How Avista Reaches These Communities
Today
•Low income assistance
•Senior/disability rate discount
•Project share
•Energy efficiency programs
•Energy fairs and workshops
•Corporate and Avista Foundation
giving
•Energy home audits
•Prevention of wood smoke part of
energy efficiency analysis
•Wildfire mitigation program
•Public access to hydro facilities
•Park development
•Neighborhood engagement when
developing projects
•Tribal hiring
•Energy pathways program
•Tribal settlements
•Hydro relicensing outreach
•Wildlife land purchases
4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 73 of 1105
IRP Requirements (Section 14)
(k) An assessment, informed by the cumulative impact
analysis conducted under section 24 of this act, of: Energy
and nonenergy benefits and reductions of burdens to
vulnerable populations and highly impacted communities;
long-term and short-term public health and environmental
benefits, costs, and risks; and energy security and risk;
Sec. 24. By December 31, 2020, the department of health must develop a cumulative
impact analysis to designate the communities highly impacted by fossil fuel pollution and
climate change in Washington. The cumulative impact analysis may integrate with and
build upon other concurrent cross-agency efforts in developing a cumulative impact
analysis and population tracking resources used by the department of health and
analysis performed by the University of Washington department of environmental and
occupational health sciences. [https://www.doh.wa.gov/CETA/CIA]
5
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 74 of 1105
How Will Avista Address These New
Requirements?
•Gain perspectives from advisory group(s) for additional
requirements or from new rules
•Identify and engage highly impacted communities &
vulnerable populations
–Advisory groups
–Encourage representatives to either participate in existing advisory
groups or potentially create a new advisory group to address the
community impacts.
•Create baseline data
•Estimate benefits/impacts from IRP
6
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 75 of 1105
Identifying Communities or “Customers”
Highly Impacted
Communities
–Cumulative Impact Analysis
–Tribal lands
•Spokane
•Colville
–Locations should be available
by end of 2020
•State held workshops in
August & September 2019
Vulnerable
Populations
–Use Washington State Health
Disparities map
•What is disproportionate on a
scale of 1 to 10?
•Avista proposes areas with a
score 8 or higher in either
Socioeconomic factors or
Sensitive population metrics
–Should we include other
metrics to identify these
communities?
7
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 76 of 1105
Environmental Health Disparities Map
https://fortress.wa.gov/doh/wtn/wtnibl/
Data by FIPS Code
8
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 77 of 1105
Environmental Health Scoring
Circle areas match definition of
vulnerable population,
although access to food &
health care, higher rates of
hospitalization are not
expressively included but are
an indication of poverty
9
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 78 of 1105
Eastern Washington Communities
Socioeconomic Factors Sensitive Populations
10
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 79 of 1105
Avista Electric Service Territory
11
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 80 of 1105
Data Analysis of Vulnerable Populations
Socioeconomic Sensitive
Avista (Mean)5.1 (5 median)6.0 (6 median)
State (Mean)5.4 (5 median)5.2 (5 median)
Avista (Stdev)2.67 2.83
State (Stdev)2.88 2.8812
Avista has 145 communities identified
•35 (24%) have an 8 or higher for Socioeconomic Factors
•55 (38%) have an 8 or higher for Sensitive Populations
•67 (46%) are considered vulnerable
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 81 of 1105
Selected Vulnerable Populations
13
Data is shown
by combined
score
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 82 of 1105
Spokane Area “Avista” Vulnerable
Populations
14
Data is shown
by combined
score
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 83 of 1105
IRP Metrics
Metric IRP Relationship
Energy Usage per Customer •Expected change taking into account selected energy
efficiency then compare to remaining population.
•EE includes low income programs and TRC based
analysis which includes non-economic benefits.
Cost per Customer •Estimate cost per customer then compare to
remaining population.
•How do IRP results compare to above 6% of income?
Preference •Should the IRP have a monetary preference?
•For example-should all customers pay more to
locate assets (or programs) in areas with
vulnerable populations or highly impacted
communities?
•If so, how much more?
15
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 84 of 1105
IRP Metrics
Metric IRP Relationship
Reliability
•SAIFI: System Average Interruption
Frequency Index
•MAIFI: Momentary Average Interruption
Frequency Index
•Calculate baseline for each distribution feeder and
match with communities
•Estimate benefits for area with potential IRP
distribution projects
•Compare to other communities as baseline
•May be more appropriate in Distribution plan rather
than IRP
Resiliency:
•SAIDI: System Average Interruption Duration
Index
•CAIDI: Customer Average Interruption
Duration Index
•CELID: Customer’s Experiencing Long
Duration Outages
Resource Analysis •Estimate emissions (NOX,SO2, PM2.5, Hg) from
power projects located in/near identified communities
•Identify new resource or infrastructure project
candidates with benefit to communities; i.e. economic
benefit, reliability benefit
•Identify how resource can benefit energy security
16
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 85 of 1105
TAC Input
•What other metrics can we provide in an IRP to
show vulnerable populations and highly
impacted communities are not harmed by the
transition to clean energy
17
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 86 of 1105
Attendees: TAC 1, Thursday, June 18, 2020 Virtual Meeting on Skype:
Shawn Bonfield (Avista), Terrance Browne (Avista), Logan Callan (City of Spokane),
Teri Carlock (IPUC), John Chatburn (Idaho Governor’s Office of Energy and Mineral
Resources), Corey Dahl (Washington State Office of the Attorney General), Thomas
Dempsey (Avista), Chris Drake (Avista), Annabel Drayton (NW Energy Coalition),
Michael Eldred (IPUC), Nancy Esteb (Renewable Energy Coalition), Chip Estes,
Rachelle Farnsworth (IPUC), Ryan Finesilver (Avista), Damon Fisher (Avista), Grant
Forsyth (Avista), James Gall (Avista), Annie Gannon (Avista), Amanda Ghering (Avista), Dainee Gibson (Idaho Conservation League), Kate Griffith (Washington UTC), Vlad
Gutman-Britten (Climate Solutions), Leona Haley (Avista), Jared Hansen (Idaho Power), Lori Hermanson (Avista), Kevin Holland (Avista), Kristine Holmberg (Avista), Tina
Jayaweera (Northwest Power and Conservation Council), Clint Kalich (Avista), Kevin Keyt (IPUC), Kathleen Kinney (Biomethane, LLC), Scott Kinney (Avista), Dean Kinzer (Whitman Co. Commissioner’s Office), Erik Lee (Avista), John Lyons (Avista), James McDougal (Avista), Matt Nykiel (Idaho Conservation League), Tom Pardee (Avista), Jørgen Rasmussen (Solar Acres Farm), John Ross, John Rothlin (Avista), Jennifer Snyder (Washington UTC), Dean Spratt (Avista), Jason Thackston (Avista), Marissa Warren (Idaho Governor’s Office of Energy and Mineral Resources), Amy Wheeless (NW Energy Coalition), and 13 Guests who did not identify themselves.

Questions and comments are identified by speaker when possible and text in italics
records the responses by the presenters.

TAC Expectations & Process Overview
John Lyons: A new stakeholder feedback form will be added to the IRP website. Slides
from this meeting will be posted on the IRP website next week. The generation resource
options spreadsheet was emailed earlier this week. Avista is also considering different
options for meetings and sharing of TAC materials, but we will continue to post meeting
notes on the website. We will attempt to record these meetings.
John Lyons: Washington now requires an IRP every 4 years with an update after two
years. Washington law (Clean Energy Transformation Act or CETA) does not allow for
the Commission to acknowledge an IRP without all of the CETA requirements and
rulemaking in place, moving the next IRP out until 4/1/21. The 2021 IRP will be
modeling 2021 through 2045 (for CETA). Avista welcomes requests for additional
studies by August 1, 2010, but earlier is better for accommodating any requests. The
dates of future TAC meetings are in the presentation and posted on the IRP web site.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 87 of 1105
2020 IRP Acknowledgement – John Lyons
IRP acknowledgement means the filing has met the rules for IRPs in both states. It
includes comments about topics to include or build upon in the next IRP.
Acknowledgement does not provide rate recovery, but is a component of rate recovery.
If a new resource wasn’t chosen in the IRP, we have more explanation required what it
was not identified in the IRP. Because of the extension for the 2020 IRP, we do not
have acknowledgements to review in this meeting. The Idaho Commission is accepting
comments from the public through August 19, 2020 with replies due from the Company
by September 2, 2020. A key area of expected concern is how Avista will develop an
IRP that accommodates Washington’s CETA requirements, but not adversely impact
Idaho customers. Washington suspended acknowledgement letter through December
31, 2020, but provided some comments on the work plan including providing an
opportunity for stakeholder input on the conservation potential assessment (CPA)
before finalization, extending participation to a broader public audience, and providing a
timeline of IRP data and when it will become available.

CETA Rulemaking Update – Shawn Bonfield
CETA applies to all electric utilities in Washington. It requires 100% clean energy, the
elimination of coal from serving Washington customers by 2025, greenhouse gas
neutral by 2030 and at least 80% clean, and 100% renewable or generated from zero-
carbon resources by 2045. CETA also requires equitable distribution of energy and non-
energy benefits and to ensure public health and environmental benefits. Avista is well
above the 15% renewable standard required under the Energy Independence Act (I-
937). Avista is about 60% clean/renewable today. 2020 is a big year for CETA
rulemaking: Phase 0 included the overall implementation plan. Phase 1 (August 2019 –
January 1, 2021) includes the already published the Social Cost of Carbon
(https://www.utc.wa.gov/regulatedIndustries/utilities/Pages/SocialCostofCarbon.aspx)
for use in resource planning and the CPA, and the initiation of other required rulemaking
dockets. Concurrent EIA draft rules are about done and hopefully will be adopted next
month. Other areas include the CEIP – how utilities will look at compliance and penalty
processes; IRP updated rulemaking – July timeframe; Purchase of Electric (impacts
RFPs) draft rules June 1 with comments due end of June with a workshop mid-July;
Department of Ecology rulemakings will identify greenhouse gas emission factors; and
plenty of other rulemaking activity at the Department of Commerce, the UTC and other
agencies.
Jennifer Snyder: Thank you. You covered it well. We (Washington UTC) appreciate
any comments and participation in the CETA rulemaking process.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 88 of 1105
Modeling Process Overview – James Gall
James Gall: Aurora in an electric market cost model that is used to simulate the
Western Interconnect. It is the industry standard model in the Northwest. Avista
implemented Aurora in 2003 and uses it for IRP and rate cases. The inputs include
regional loads, fuel prices, resource availability, new resource costs, transmission, and
system constraints. Outputs include market prices, energy mix, transmission usage,
emissions, power plant margins, generation levels, fuel costs and variable power supply
costs to serve loads by year. Market price forecast helps us develop a purchase/sales
strategy. The model dispatches to meet hourly loads in each area and tries to match
supply with demand or loads and resources. Market price is based on the price for the
last, or marginal, plant to turn on for that hour.
Matt Nykiel (Slide 3): I have a better understanding of Aurora after participating in the
last IRP. For slide 3 inputs and following, I’d like a general understanding of what inputs
are public and private in Aurora. We’ll cover some here and there is a slide later that
cover more. The database from EPIS is proprietary and they use it for all of their clients
who are Aurora license holders. It is largely based on publically available information
from EIA, EPA, etcetera, but we can’t release it per our license. There are adjustments
for Avista including data that will be changed to reflect our contracts, pricing, and
operational requirements and how we operate our resource which are proprietary. We’ll
describe more alter in the presentation. Thank you.
James Gall: Deterministic studies are single point estimates with median hydro and
expected loads. They are easy for scenario analyses. Stochastic studies use the
expected case or preferred portfolio providing a range of results. The model runs 500
times with different inputs in order to understand risk or volatility. Avista uses the mean
value of stochastic analysis for its expected case. Stochastic studies provide better
representation of expected value of resources. The model assumptions start from 2020
IRP. We use the same database available from Energy Examplar today; then update
natural gas prices, new resources and retirements, include new laws, review
load/resource assumptions for EVs, rooftop solar, new resource costs, add Avista
proprietary system info and stochastic distribution of regional hydro, natural gas, wind
and loads. We will provide what’s not confidential. The Aurora run process-request input
will need to be done ASAP, finalize inputs, run long term studies to estimate new
resource additions and will show results at next TAC. We will test under 500 simulations
and test a future year – 2035. The deterministic run tests reasonableness. The
stochastic run takes 3 weeks to run the scenarios. It is a very tight timeline. The outputs
will show how profitable each of the resources are to understand dispatch under CETA.
This helps us value the cost to serve, estimate emissions, understand changes to the
regional market such as volatility, emissions, etc., and the data used for PRiSM.
Matt Nykiel (Slide 7): You mentioned long-term study. Is this what Avista thinks how
the region will meet demand? Is this Avista’s interpretation or is it based on other
utilities that have their own IRPs? That’s a good question. It’s multiple ways. We
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 89 of 1105
typically have not utilized other utility’s IRPs since they only cover a portion of the area
and could be dated. Some utilities don’t do IRPs. We look at the region of load
obligations, the current resource mix, and state requirements. The model selects new
resources for most cost effective for those load areas given our cost assumptions. We
have also looked at other studies, consultant data for storage and small renewables.
This is a fairly industry standard approach.
James Gall: PRiSM is where all of the models come together from an input perspective
to make resource decisions. It is internally developed. We input resource needs and
options. The model will select resources that meet needs based on constraints. ‘What’s
Best’ is the solver function – min/max of a variable to optimize the value with unlimited
variables/constraints. What’s Best plus Gurobi speeds up optimization especially when
considering so many inputs such as energy efficiency. The outputs include the power
supply costs (fixed + variable) and variation; selection of new resources, etc. We design
the model to add new resources to serve Washington, Idaho or combined customer
requirements. We will split our resource cost using the P/T ratio [35% Idaho and 65%
Washington]. States may sell RECs to help recover customer costs.
James Gall (Slide 10): The last IRP showed that Colstrip was not cost-effective past
2025. We will reevaluate Colstrip in this plan as no decision has been made. After 2025,
since we’re splitting by state in PRiSM for the resource balance, Idaho will still receive
its 35% share of Colstrip unless it’s determined that it will be retired. There is an option
to retire in Colstrip in 2025 or in the future.
Vlad Gutman-Britten: Does the future year on the chart incorporate potential climate
change? Typically impacts include from climate change include load and hydro. We are
open to for 2045 about how climate change impacts these forecasts
John Lyons: Grant [Forsyth] picks these changes up in his load forecast.
Grant Forsyth: I try to look at how temperatures change. The approach is a moving
average for weather. People can ask more about that during my presentation in the next
TAC meeting [August TAC].
James Gall (Slide 11): The Social Cost of Carbon (SCC) is required for Washington
under CETA. We will run the model to get the expected amount of emissions for each
resource. This is for long-term not short-term resources. We will calculate emissions
from short-term resources and may cover those at a future TAC. We will not include
SCC for biomass or geothermal since those resources are specifically outlined in law, or
for Idaho, but we could consider including for Idaho as a scenario if the TAC wants.
James Gall (Slide 12): SCC pricing – 2007 $ and discounted 2.5% (on the lower
range). Will use the green line in the chart which starts at $80 per ton. We move prices
from 2007 to 2019 and inflate based on our annual inflation rate of 2.11%.
James Gall: (Slide 13): Issues Not Finalized. We may transfer RECs between states,
but must determine the price to transfer RECs at. We will need input on if we need to
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 90 of 1105
consider transferring more than 20% if there is an economic benefit. How do we count
RECs toward the 80%? Will this be hourly or over the four-year compliance period? If
we receive no clarification, we will need to make assumptions to model the IRP. This
may be the biggest rulemaking from CETA that the UTC needs to resolve, hopefully in
early fall, so it can be modeled correctly for this IRP.
James Gall (Slide 14): Reliability planning. We estimate probability of failure to serve
all load to a regional standard of 5%. To evaluate whether a portfolio is reliable – PRM
(planning reserve margin) is the percentage above the expected load measured by the
coldest day of each month averaged by that temperature, load requirement, plus
planning margin. This helps us understand how much we can rely on certain resources.
The gold standard would be a region wide program with enforced requirements for each
utility. Currently, the region is looking at moving toward this model, but probably not in
time for this IRP. So, we need to decide how much time we invest in this issue now.
ELCC (Electric Load Carrying Capability) – improvement by focusing on additional
years, sampling every 5 years, peak credits or peak types. As you add intermittent
resources peak value declines. We haven’t ran an ELCC for each resource to determine
how much the peak contribution reduces over time.
James Gall (Slides 15 – 17): Reliability study models to consider. ARAM model is used
currently and is customized (not for this IRP). Aurora has ability to dispatch hydro – not
as good when the system is stressed leading to over acquisition. Genesis is an option
for the future. We can purchase software/hire consultant – this is costly and not
currently being looked at. Regional Resource Adequacy Market – could be used for a
future option. Two areas of focus are ARAM and Aurora – likely our current model with
a single year and possibly scenarios, but we can’t commit to every year, use 2020
ELCC (peak credits) scenario on resource adequacy. We will keep the TAC updated
throughout the process.
James Gall (Slide 18): Data availability – proposal, we are interested in feedback for.
Avista-specific data and Energy Exemplar database is proprietary, prices, regional
emissions, not dispatch (confidential), high level results including PRiSM, won’t be able
to make inputs and resolve (requires license), big change from prior IRPs, load forecast
models are confidential because of customer-specific information. We will provide
monthly energy/peak results by state, resource costs (you already received); demand-
side data will include a list of energy efficiency programs available, may not be fully
available in July/August so we may have a short, 1-hour workshop when that data
becomes available. DR programs and their potential. Transmission/distribution models
are confidential and will be a TAC 3 discussion. Reliability – ARAM requires a license so
you can’t input and resolve, but we are researching to ensure we can make it available.
Michael Eldred: I have a question of how you are testing for reliability. LOLP in 2035,
500 times in that year. The percent probability load not met. The goal is 95% meeting in
all times. In most cases it does. If results are grossly inadequate and outside the margin
of error, we rerun the study. Does that help? Yes, thank you.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 91 of 1105
Matt Nykiel: LT study, when Avista is looking over a range of resources is it taking into
account things like customer owned generation over time as roof top solar reduces
demand on IOUs? Good question. Slide 6 specific adjustment made to model. We will
present assumptions in the market price meeting. Definitely an area we will have to
consider.
Matt Nykiel: Recall that was an analysis for Avista, but how meeting regional WECC
loads but in area. Yes, we look at both inside Avista and outside the service territory.
Looking to point to the right spot in the last IRP. Typically not a lot of discussion. It is a
small but important input. Will definitely talk about it in the next TAC.
James Gall: I appreciate the better interaction on these questions.
Tina Jayaweera: I’m interested in more about emissions savings in energy efficiency
and demand response. DR is challenging and depends on program – some reduce and
some shift loads, and the likelihood of a DR program being called on based on program
design could be a challenge. Energy efficiency typically uses an hourly profile of savings
compared to hourly emissions from Aurora – possibly could run a scenario to see how
emissions change by the hour. We can do this for the deterministic but not all 500 runs.
Could show incremental savings.
Dainee Gibson: A lot of CETA requires the model to be able to split differences
geographically. Can Aurora split it by state or does it apply to the entire service
territory? Sure. We could split it by state, but it doesn’t model the physics well. Now we
talk about region as a whole. The OWI bubble in Aurora can’t split by state really well,
since the system doesn’t recognize state boundaries. Avista in PRiSM is where we talk
about how we split resources by state from a resource planning perspective.
Kevin Keyt (Slide 10): I understand the 65/35 split historically, but it appears
incremental legislation in Washington may split differently. Maybe the model equals
65/35 for existing resources and the split of new resources are an output of the model. I
don’t want to volunteer you for a bunch of runs, but want to understand how it might
change. We may shift from a cost to a load balance.
Vlad Gutman-Britten: CETA requires 100% in 2045, but Avista corporate goal is 100%
by 2027. How do you account for that? Excellent question. If cost effective, we will do it.
Will run a scenario to meet the goal and it becomes a management decision on
reaching 2027 and 2045 goals to set the strategy going forward based on the cost to
customers. Last IRP, we were 90% clean without additional costs beyond CETA. At that
time, management was not willing to put that additional cost on customers for the
remaining 10 percent.
Matt Nykiel: In PRiSM, are there parameters that require Avista service territory to
meet the goal in 2027 and 2045 for the entire service territory? Carbon neutral by 2027
and 2045 is not meaningful if not cost effective from the get go. I don’t understand the
goal if it doesn’t have an impact
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 92 of 1105
Jason Thackston: Good question and the point is appreciated. I appreciated the way
James answered. What we said, and are still committed to, is affordability and reliability.
We are still committed to those goals, but reliability will not be sacrificed and the goal is
subject to affordability by the impact on customers’ bills. We always look at cost-
effective, but trying to be more holistic. Does that help?
Matt Nykiel: I’d like to learn more.
Terri Carlock: To clarify, you will run the full system to meet that commitment and
looking at the costs separately for both states to decide whether you implement in both
states and the Commissions will each review. That is a fair and correct summary. Still
need guidance by states before we can fully state how we model.
Vlad Gutman-Britten – Are you selling REC between states? About ready to talk about
that. If 20% REC only or bundled. Idaho to Washington for Rulemaking is still being
considered relative to this and bundling so I can’t answer specific questions on how
we’ll be modeling until the rulemaking is more final. We will likely try to simulate REC
sales similar to our last plan.
Vlad Gutman-Britten: So Idaho would have a higher fossil fuel content than
Washington? Correct.
Matt Nykiel (Colstrip): What does it mean to have a shareholder portfolio? One
question, I don’t understand why if Units 3 and 4 are uneconomic, why is the
Washington share only going to shareholders? Need to model it to decide where it
goes. We are redoing same analysis so the Idaho portion only serves their load. If the
model chooses 2025, or another date, to close for economics. The shareholder portfolio
is because it can’t be in Washington rates after 2025 under CETA, but if it is still
operating, we still have to sell off or consume those megawatt-hours.
Jason Thackston: Correct me if what I say is incorrect. There are two outcomes. One.
Assume all same as last IRP, after 2025 Colstrip is not in the portfolio because it is not
economic. Two. Very extreme. Everything doubles and Colstrip is way in the money, it
should still be in the portfolio beyond 2025, but it is not viable in Washington. It would
still be, absent a decision to shut down the plant. Nuance in Washington State the
model has to reflect.
Matt Nykiel: That’s helpful. Thank you.
Terri Carlock: What shareholder portfolio costs would be associated for any costs
extending the life of the plant? Washington depreciation done in 2025 for Colstrip. Any
other O&M, capital, or fuel at that time will be on shareholders. Washington will still
cover their shutdown costs for the time it was on their system.
Matt Nykiel (Slide 10 – PRiSM): I don’t mean to belabor the point, first bullet point,
does it respect state guidelines? How will the model in practice split up new resource?
We don’t have all the answers regarding specific actual operations. From a modeling
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 93 of 1105
perspective for adding or subtracting resources we continue to operate as a whole
system. Operations is as a single system. From a clean energy perspective, we can
assign whether or not power is clean, etcetera on an accounting basis not a physics
basis. Accounting rather than an engineering basis. Appreciate more discussion in the
future.
Terri Carlock: Same for market purchases? Still rules to come. I hope regulating
bodies don’t rush it because of lasting impacts of the decision.
Jennifer Snyder: Are you including social cost of carbon on new construction and
operation of new or existing resources? Just new, but there are there processes at the
generation site that add to emissions. Trucks for hauling fuel at Kettle Falls and other
equipment, trucks to maintain wind farms. NREL has some older studies estimating
these types of emissions as well.
Matt Nykiel: SCC is a reflection of the understanding of GHG cost not being
internalized by facilities that emit them. Is Avista incorporating this cost due to the legal
requirements not because Avista is acknowledging that GHG have a cost that’s not
being internalized? Its Avista’s understanding of a cost just as a legal operation, not as
a corporate entity. Makes sense. One way to interpret it.
Jason Thackston: I’m not sure I’m the best one to answer, but generally speaking you
have captured it for Washington legislation and Washington feedback.
Tina Jayaweera: Upstream value for emissions? Next TAC meeting, but Avista gas line
rights are very different than the distribution side. We source our gas mostly from
Canadian sources so we’re focusing on the emission for the gas we’re sourcing.
Jennifer Snyder: Issues not finalized, what date do you need clarification by for
RECs/CETA? REC transfers by September [2020] at the latest. Earlier is better. If not
clarified by then, we would run multiple scenarios or possible outcomes.
Matt Nykiel: Bundled RECs, can Avista transfer energy plus RECs associated with
that? Multiple interpretations of the options. Power, REC, power plus REC or separate
the two and combine with others. The way bundled or not is the difference for
Washington CETA in different contexts. Depending on how WUTC rules, we could have
to way overbuild because of REC needs. Treat as I-937 or actually serve
instantaneously.
Rachelle Farnsworth: So can you tell more on how and why it is Washington
establishing the price of REC transfers between states? Hopefully I didn’t say that.
Washington sets the requirement for how many RECS are required. Then it is a
question of what price is needed to meet Washington law. I.e., the price is $20 so the
model says build for Idaho to sell to Washington. Price matters depending on outcome
in model. Much as last time, if economic to build for state and take advantage of the
market if available. Three examples at different prices: example price of a REC at $20,
Idaho should build a project to sell to Washington. If valued at $0, Idaho wouldn’t build.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 94 of 1105
We wouldn’t want to see the model build based on resources to sell to Washington, but
would build the least cost to take advantage of the market.
Kevin (IPUC) – have you defined requirements for Reliability modeling (document would
be helpful)? James - slide 14 95% of simulations serve 100% load and reserve
requirements; don’t want to start down the path of buying new software if the regional
market is coming soon
Kevin Keyt (Slide 14): Have you defined requirements for reliability models and
decision making? 95% LOLP of simulations serve 100% of load requirements and we
look at other metrics too. In terms of software development and modeling tool, we want
to produce some confident results. There is a cost to maintain/operate a reliability
model. Timeline is short for this plan, so we don’t want to go too far if a resource market
overseer is coming. Maybe the new Genesis model. Maybe a new overseer. Don’t want
to have to scrap a new model in a year or two.
Modeling Process Overview Continued After Lunch Break – James Gall
Matt Nykiel: I appreciate the transparency. I notice it in the slides already. For Aurora,
I’d like to understand Colstrip inputs better. If Units 3 or 4 continues to be uneconomic
for Idaho from modeling, how would the Idaho share go into a shareholder portfolio?
Aurora gives a price forecast valuing resources not by ownership. Dispatch the plant
with a heat rate and fuel costs that influence market price if economic to run. If PRiSM is
not cost effective, do we retire or close the plant? If it goes out, need to decide how – if
closed or sold. PRiSM more utility based.
Matt Nykiel: Make sure the model is looking at price to meet minimum take obligations.
If it becomes uneconomic for Idaho, does the IRP consider where that minimum energy
goes? If it goes out of the Idaho portfolio, it jumps from planning to action. If we remove
it from Idaho, Idaho no longer bears the expense. We reevaluate it at every IRP cycle.
Nothing changes here from how we model in last IRP
Matt Nykiel: Mentioned earlier it accounts for shut down, forced outages and needed
repairs. Unit 4 is expected to need repairs to the super heater. Does the model account
for those expected repairs? This can affect ownership issues not agreed to under
sections of the contract. I can’t and maybe shouldn’t comment on a contract. It includes
expected and potential repairs.
Generation Resource Options – Lori Hermanson
James Gall: We are seeking feedback from the TAC about if we should model generic
or specific resources regarding pumped hydro storage.
Jennifer Snyder: Don’t have rates impact now. But lean towards specific projects if
data available.
Terri Carlock: Doesn’t pumped hydro storage depend on scale?
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 95 of 1105
James Gall: A generic resource would need an assumption for duration and cost.
Hybrid concept we used last time. But some projects have attributes with lower or
higher costs. We got comments last time from some TAC members. We modeled one
specific pumped hydro resource and some TAC members thought we should have
modeled others. Then what about specific wind and solar projects? That means we are
doing an RFP in an IRP.
Kathleen Kinney: I have some sources on renewable hydrogen gas you can email me
about. We will email you. Renewable natural gas will be discussed in the next TAC
meeting.
Amy Wheeless: I acknowledge the conundrum. Did you reach out to the renewable
hydrogen alliance? We did not. We used Black & Veatch last time. Also had comments
from a vendor on gas turbine retrofits for hydrogen gas.
Matt Nykiel (Slide 3): Can you explain what in the analysis that caused gas prices to
increase. 2020 is an estimate of 2022. Mostly inflation and the price of gas. They are
effectively the same.
Matt Nykiel (Slide 10): What is the northwest for solar? Southern Idaho? Are we
looking at Idaho? Southern Idaho or Oregon with a BPA wheel to get to Avista. We are
indifferent on location, this is showing the costs and benefits of solar in a better location.
Jørgen Rasmussen: Is liquid air storage included? Yes, see slide 7, we are modeling it
again. It was selected in the last plan.
Thomas Dempsey: We will be reviewing the liquid air energy storage costs further in
this plan.
Review of spreadsheet with resource costs and operating characteristics:
James Gall: I’ve been involved with half a dozen RFPs. Prices vary widely and will be
different than the generic modeled prices. We are really seeking input on these costs
and assumptions.
Vlad Gutman-Britten: Environmental burdens are a wider scope, not just greenhouse
gas emissions.

Washington Vulnerable Populations and Highly Impacted Communities – James
Gall
James Gall: Vulnerable populations consider socioeconomic factors and income
sensitivity factors. Avista already recognizes that nearly half of our territory is low
income and we are economically involved in our communities. This part of CETA is
currently in the rule-making process. We hope the TAC and other advisory groups will
help guide us in how to address these new requirements. It is possible a new advisory
group is needed or we may get more participants in the current TAC or another group.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 96 of 1105
We need to gather more data and better understand our baseline – where are they at
today? The Washington State disparities map rates each census tract between 1 and
10 for socioeconomic factors which seems to align with the proposed rules. We are
proposing score of 8 or higher to be considered vulnerable or impacted. We will overlay
this on our service territory, noting that Idaho is not subject to CETA. There are
overlapping service territories with other utilities in some of the vulnerable areas.
Average use per customer – two sets and compare how they change over time. We use
that information to estimate how costs can change over time. Whether or not customers
have more than 6% of their income goes toward energy. Should the IRP have a
monetary preference for these areas, no preference, or no additional preferences?
Reliability/Resiliency metrics are available by feeder. We can show this at a future TAC
meeting and compare to the remaining areas. There is a challenge for how this relates
to the IRP. For Resource analysis, we can estimate emissions from our facilities located
near or removed from these areas. If a new resource, we can discuss how those may
change in those areas. Energy security is challenging. The grid works together for the
benefit of all customers, not necessarily for certain populations.
Kate Griffith: Regarding DOH map. The state Environmental Justice Taskforce is
working on guidance as the mapping tool is being developed among other tasks. They have regular meetings. More info is here: https://healthequity.wa.gov/TheCouncilsWork/EnvironmentalJusticeTaskForceInformation.

Vlad Gutman-Britten: Note that the tracts aren't categorized in a population weighted
way, so the three most impacted deciles of tracts may not correspond to the three most
impacted deciles of people.

Jennifer Snyder (Slide 7): No good updates to add [concerning the identification of
highly impacted communities or vulnerable populations].

Amy Wheeless: How do you define community? Identified by census tract, so each
colored area in Slide 10 is a community.
Vlad Gutman-Britten: It would be helpful to understand how community compares to
population and customer share and load share. Excellent questions. We’re going to get
to that in metrics.

Shawn Bonfield (Slide 14): What do the figures on the map represent? The numbers
are census tracts and the darker shaded areas are more vulnerable.

Kate Griffith: Do you have a sense for the particular sensitivity factors in Spokane? I
apologize, I mean the issues they face such as low birth rates, etc. I don’t know that information.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 97 of 1105
Vlad Gutman-Britten: The Department of Health map provides component scores, in
addition to the rolled up score. Thank you.

Amy Wheeless: Some of the CAP [Community Action Partnership] agencies may be
able to provide more qualitative information.

Vlad Gutman-Britten: Yes, monetary preference and extra inducements are important
and would go toward equalizing going forward since they haven’t received these
resources in the past. Equity is worthwhile to perform and pursue. How much is
required? Think about what will be necessary for success.
Kate Griffith: How is Avista working to contact and engage with these communities
around planning? Have you started reaching out to these groups or communities? We
need direction. Are these separate advisory groups. We have had some participation in
the past on the TAC from tribes and SNAP. They are not always able to attend. We
need to reach out to public officials in these areas and need more outreach and
opportunities to include these groups. More to come on this.
Jennifer Snyder: What metrics make sense? It would be helpful to have more
representation from these groups for these particular committees to understand what
issues to address.
Corey Dahl: I’ll second conducting outreach. What does it look like? How to address equity? The company has both an obligation to select the lowest cost resource, but a
need to comply. Example off the top of my head not sure if real. Natural gas generation facility goes offline and is replaced with solar benefits to the surrounding community, but
also benefits of transmission. But jobs are lost. Jennifer Snyder: What type of long- and short-term public health benefits have you looked at? Potentially for DSM and supply-side resources? Example, wood smoke in
energy efficiency. Including things from a TRC point of view. Concentrate on emissions with existing generation. Are there others? Jennifer Snyder: There are things we didn’t take into consideration prior to CETA, but
we should. There are a lot of health benefits in some jurisdictions. Not in Washington yet, but new things not taken into account before CETA. James Gall: One other is interplay of gas and electric service territory.
Amy Wheeless: The past few slides spurred a lot of thoughts. I’m not really involved
with the CETA rulemaking. Great questions to bring forward. Seek potential future and get cost benefits.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 98 of 1105
James Gall: Can look at distribution or opportunities that might be higher cost, but see
what those costs might be. The topic will come up again to show some of these metrics.
Let John [Lyons] or myself know of any thoughts you have.

Kate Griffith: Are these the metrics you’re planning to bring into the CEIP? So far. We
may have additional metrics later with input. Meaningful and calculable metrics for a
more useful set of data.
Kate Griffith: You mentioned quantifiable, but non quantifiable is also a big piece of this
so I’d be interested to hear more about incorporation of less measurable equity measures. We are looking for any ideas we can look at.

Meeting adjourned.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 99 of 1105
2021 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 2 Agenda
Thursday, August 6, 2020
Virtual Meeting- 9:00 AM PST

Topic Time Staff
Introductions & IRP Process Updates 9:00 Lyons
Natural Gas & RNG Market Overview 9:30 Pardee Break 10:45
Natural Gas Price Forecast 11:00 Brutocao
Lunch 11:30
Upstream Natural Gas Emissions 12:30 Pardee

Break 1:30 Regional Energy Policy Update 1:45 Lyons
Natural Gas and Electric Coordinated 2:15 Gall/Pardee
Study Highly Impacted & Vulnerable Populations 3:00 Gall Baseline Analysis

Adjourn 3:45

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 100 of 1105
2021 Electric and Natural Gas IRPs
TAC Introductions and IRP Process
Updates
John Lyons, Ph.D.
Second Technical Advisory Committee Meeting
August 6, 2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 101 of 1105
Updated Meeting Guidelines
•Gas and electric IRP teams working remotely, but still
available by email and phone for questions and
comments
•Some processes are taking longer remotely
•Virtual IRP meetings until back in the office and able to
hold large group meetings
•TAC presentations, notes, work plans and past IRPs are
posted on joint IRP page for gas and electric:
https://www.myavista.com/about-us/integrated-resource-
planning
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 102 of 1105
Virtual TAC Meeting Reminders
•Please mute mics unless speaking or asking a question
•Use the Skype chat box to write questions or comments
or let us know you would like to say something
•Respect the pause
•Please try not to speak over the presenter or a speaker
who is voicing a question or thought
•Remember to state your name before speaking for the
note taker
•This is a public advisory meeting –presentations and
comments will be recorded and documented
3
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 103 of 1105
Integrated Resource Planning
•Required by Idaho, Oregon and Washington* every other
year
•Guides resource strategy over the next twenty + years
•Current and projected load & resource position
•Resource strategies under different future policies
–Resource choices
–Conservation measures and programs
–Transmission and distribution integration for electric
–Gas distribution planning
–Gas and electric market price forecasts
•Scenarios for uncertain future events and issues
•Key dates for modeling and IRP development are
available in the Work Plans
4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 104 of 1105
Technical Advisory Committee
•The public process piece of the IRP –input on what to study, how to
study, and review of assumptions and results
•Wide range of participants involved in all or parts of the process
–Ask questions
–Help with soliciting new members
•Open forum while balancing need to get through all of the topics
•Welcome requests for studies or different assumptions.
–Time or resources may limit the number or type of studies
–Earlier study requests allow us to be more accommodating
–August 1, 2020 was the electric study request deadline
•Planning teams are available by email or phone for questions or
comments between the TAC meetings
5
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 105 of 1105
2020 Electric IRP Meetings – IPUC
•AVU-E-19-01 https://puc.idaho.gov/case/Details/3633
•Telephonic public hearing on August 5, 2020
•August 19, 2020 comment deadline, September 2, 2020 response
•Overview of topics discussed at July 9, 2020 virtual public workshop:
–Moving away from coal
–Cost impacts for Idaho customers from Washington laws
–IRP procedural questions about acknowledgment of the IRP
–Climate change questions and timing of actions
–Colstrip: decommissioning, other owners, cost sharing with Washington
–Consideration of social costs/externalities and public health
–Support for clean energy and Commission authority to require it
–Resource timing
–Risks considered in the IRP: economic, qualitative and climate
–Idaho versus Montana wind locations
–Maintaining Idaho RECs
–Climate change law applicability and lawsuits6
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 106 of 1105
2021 Natural Gas IRP TAC Schedule
•TAC 1: Wednesday, June 17, 2020
•TAC 2: Thursday, August 6, 2020 (Joint with Electric TAC)
•TAC 3: Wednesday, September 30, 2020
•TAC 4: Wednesday, November 18, 2020
•TAC 5: February 2021 –TAC final review meeting if necessary
•Natural Gas TAC agendas, presentations and meeting minutes
available at: https://myavista.com/about-us/integrated-resource-
planning
7
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 107 of 1105
2021 Electric IRP TAC Schedule
•TAC 1: Thursday, June 18, 2020
•TAC 2: Thursday, August 6, 2020 (Joint with Natural Gas TAC)
•Economic and Load Forecast, August 2020
•TAC 3: Tuesday, September 29, 2020
•TAC 4: Tuesday, November 17, 2020
•TAC 5: Thursday, January 21, 2021
•Public Outreach Meeting: February 2021
•TAC agendas, presentations and meeting minutes available at:
https://myavista.com/about-us/integrated-resource-planning
8
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 108 of 1105
Process Updates
Economic and load forecast delay
•Special meeting 1:00 –3:30 pm PST on Tuesday, August 18 or
Wednesday, August 19, 2020 to cover the forecasts
AEG Conservation Potential Assessment and Demand
Response Studies –delayed from TAC 2
•AEG has developed baseline assumptions, market profiles and
energy/gas use per customer
•Market data has been collected and compiled
•Measure Assumption development is complete
•Compiled 2021 Power Plan Assumptions
•Measure List is in-process and is expected to be available mid-
September
•CPA discussion with TAC –September TAC meeting.
9
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 109 of 1105
Today’s TAC Agenda
9:00 –Introductions & IRP Process Updates, Lyons
9:30 –Natural Gas & RNG Market Overview, Pardee
10:45 –Break
11:00 –Natural Gas Price Forecast, Brutocao
11:30 –Lunch
12:30 –Upstream Natural Gas Emissions, Pardee
1:30 –Break
1:45 –Regional Energy Policy Update, Lyons
2:15 –Natural Gas and Electric Coordinated Study, Gall/Pardee
3:00 –Highly Impacted & Vulnerable Populations Baseline
Analysis, Gall
3:45 –Adjourn
10
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 110 of 1105
Natural Gas Market Overview
Tom Pardee, Natural Gas Planning Manager
Second Technical Advisory Committee Meeting
August 6, 2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 111 of 1105
Units
Common Gas Units
1 Bcf 1 Dth 1 Therm
kWh 302,062,888 293.001 29.300
MWh 302,063 0.293 0.029
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 112 of 1105
Avista Electric Territory
Avista Natural Gas Territory
Station 2
AECO
Sumas
Malin
Electric Power Plants
Northwest Pipeline
Gas Transmission NetworkKingsgate
Receipt Point
Jackson Prairie Storage (LDC Owned)
Stanfield
NGTL System
(Production and
Gathering
Systems)
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 113 of 1105
Avista’s Supply
•Natural Gas LDC Side
–10% contracted from US supply basins
–90% contracted from Canadian supply basins
•Electric Side
–100% contracted from Canadian supply basins
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 114 of 1105
US Demand
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040
%
o
f

D
e
m
a
n
d
% US Gas Demand
Residential Commercial Industrial Power LNG Exports Net Mexican Exports Transport Other
0
20
40
60
80
100
120
140
2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040
bc
f
d
US Gas Demand
Residential Commercial Industrial Power LNG Exports Net Mexican Exports Transport Other
Source: Wood Mackenzie2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 115 of 1105
US Supply
0
20
40
60
80
100
120
140
2010 2013 2016 2019 2022 2025 2028 2031 2034 2037 2040
bc
f
d
US Gas Supply
Production Canadian Net Imports LNG Imports
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
bc
f
d
Rockies San Juan Gulf Coast Gulf of Mexico
Permian Fort Worth Northeast West Coast
Alaska Mid-Continent
Source: Wood Mackenzie2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 116 of 1105
Canadian Supply and Demand
0
5
10
15
20
25
30
2010 2013 2016 2019 2022 2025 2028 2031 2034 2037 2040
bc
f
d
Canadian Gas Demand
Residential Commercial Industrial Power
LNG Exports Piped exports Transport Other
88%
90%
92%
94%
96%
98%
100%
2011 2014 2017 2020 2023 2026 2029 2032 2035 2038
bc
f
d
Canadian Supply
WCSB Eastern Canada
Source: Wood Mackenzie2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 117 of 1105
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 118 of 1105
-
5
10
15
20
25
30
35
Bc
f
pe
r

D
a
y
North American LNG Exports
Cove Point Elba Island Sabine Pass Cameron
Freeport Corpus Christi Golden Pass Calcasieu Pass
Kenai Woodfibre LNG LNG ELA Generic LNG ETX Generic
LNG WLA Generic Costa Azul LNG Canada LNG Western Canada Generic9
*WM does not assume Jordan Cove will enter service within forecasted period Source: Wood Mackenzie
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 119 of 1105
West
2020 H1
Census Region Map
Note: Pacific does not include Alaska or Hawaii
-
2.00
4.00
6.00
8.00
10.00
12.00
14.00
16.00
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
Bc
f
pe
r

D
a
y
Total Demand by Census Region
Mountain Pacific
Source: Wood Mackenzie2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 120 of 1105
-
0.05
0.10
0.15
0.20
0.25
0.30
0.35
0.40
0.45
0.50
Bc
f

p
e
r

D
a
y
Transport
Mountain Pacific
-
0.50
1.00
1.50
2.00
2.50
3.00
Bc
f
pe
r

D
a
y
Power Generation
Mountain Pacific
Power Generation and Transport demand
Source: Wood Mackenzie2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 121 of 1105
-
0.20
0.40
0.60
0.80
1.00
1.20
1.40
1.60
1.80
2.00
Bc
f

p
e
r

D
a
y
Residential
Pacific Mountain
-
0.50
1.00
1.50
2.00
2.50
3.00
3.50
Bc
f

p
e
r

D
a
y
Industrial
Pacific Mountain
West demand of Res-Com-Ind
-
0.20
0.40
0.60
0.80
1.00
1.20
Bc
f

p
e
r

D
a
y
Commercial
Pacific Mountain
Port of Kalama –NW
Innovation Works
Source: Wood Mackenzie
Source: Wood Mackenzie
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 122 of 1105
Wood Mackenzie Disclaimer
•The foregoing [chart/graph/table/information] was obtained from the [North America Gas Service]™, a product of Wood Mackenzie.”
•Any information disclosed pursuant to this agreement shall further include the following disclaimer: "The data and information provided by Wood Mackenzie should not be interpreted as advice and
•you should not rely on it for any purpose. You may not copy or use this data and information except as expressly permitted by Wood Mackenzie in writing. To the fullest extent permitted by law,
•Wood Mackenzie accepts no responsibility for your use of this data and information except as specified in a written agreement you have entered into with Wood Mackenzie for the provision of such of such data and information
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 123 of 1105
Us Natural Gas Storage
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 124 of 1105
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
#
o
f

R
i
g
s
US Rig Count History
Oil Gas Misc15
0
100
200
300
400
500
600
700
#
o
f

R
i
g
s
Canadian Rig Count History
OIL GAS MISC
Rig Counts
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 125 of 1105
Production and Drilling efficiency
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 126 of 1105
Historic Cash prices
(Jan. 1997 –July 2020)
$0.00
$2.00
$4.00
$6.00
$8.00
$10.00
$12.00
$14.00
$16.00
$18.00
$20.00
$
p
e
r

M
M
B
t
u
17
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 127 of 1105
Upstream Emissions
Tom Pardee
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 128 of 1105
Upstream Emissions
•Use based greenhouse gas emissions at the point of combustion
and include upstream methane emissions
•Link for Natural Gas Advisory Committee information on upstream
methane: https://www.nwcouncil.org/energy/energy-advisory-
committees/natural-gas-advisory-committee
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 129 of 1105
Global warming potential (GWP) factors for conversion
to CO2 equivalents (CO2e)
5th Assessment of the Intergovernmental Panel on Climate Change
Greenhouse Gas GWP –100 Year GWP –20 Year
CO2 1 1
CH4 34 86
N2O 298 268
https://www.c2es.org/content/ipcc-fifth-assessment-report/
Global Warming Potential
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 130 of 1105
Upstream Emissions Sources and Estimates
•Rockies emissions –The EPA estimates all leakage through a bottoms up
analysis. It will estimate leaks based on equipment operated as designed
and combines these values to determine an overall rate of 1%. The
emissions and sinks study is published yearly and will capture emissions as
they change.
•Canadian emissions (British Columbia and Alberta) –A value of 0.77% was
developed from data pertaining to the recent environmental impact studies
for the PSE Tacoma LNG plant, Kalama Manufacturing and Export Facility
and the 2019 Puget Sound Energy IRP.
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 131 of 1105
WSU Natural Gas Methane Study
•Sponsored by EDF and utilities to estimate the leakage of
distribution systems
•National project and estimated a loss of 0.1 –0.2 percent of the
methane delivered nationwide
•Western region contributes much less as compared to the East
•“Out of 230 measurements, three large leaks accounted for
50%of the total measured emissions from pipeline leaks. In these
types of emission studies, a few leaks accounting for a large
fraction of total emissions are not unusual.”
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 132 of 1105
LDC Upstream Emissions
*Avista gas purchases
An average of the total volume purchased over the past 5
years by emissions location2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 133 of 1105
Electric Upstream Emissions
*Avista Purchases
All firm transportation to supply gas is located in Canada2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 134 of 1105
Renewable Natural Gas (RNG)
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 135 of 1105
What is Renewable Natural Gas (RNG)?
Renewable Natural Gas
= Natural
Gas
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 136 of 1105
Why does RNG matter?
Climate Change Solution
•Natural gas plays critical role for meeting aggressive green house gas
(GHG) reductions goals, RNG even more so!
•Utilizes existing infrastructure
•Advantages of RNG
–“De-carbonizes” gas stream
–Gives customers another renewable choice
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 137 of 1105
Carbon Intensity
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 138 of 1105
RFS and LCFS Effect on RNG Value
RIN = renewable identification number
Source: CARB
Source: EPA2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 139 of 1105
What are the challenges & barriers?
•California RNG market ($30+/Dth v. $2/Dth)
–Vehicle emission incentives shut-out other potential end users
–Producers see the pot of gold in California
•Financing for producers
–RIN market is volatile
–No forward pricing for RNG RINs in carbon market
–Vehicle market may be approaching saturation in CA
–Producer/LDC partnerships may make sense
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 140 of 1105
WA RNG Report (HB 2580)
*Released December 1, 2018
WSU Energy Program, Harnessing Renewable Natural Gas for Low-Carbon Fuel: A Roadmap for Washington State
0
500,000
1,000,000
1,500,000
2,000,000
2,500,000
Cedar Hills
Landfill (King
County)
Roosevelt
Landfill
(Republic
Services)
KlickitatCounty PUD
South
Treatment
Plant (King
County)
Puget SoundEnergy
Landfills Wastewater
treatment
plants
Dairy
digesters
Municipal
food waste
digesters
Food
processing
residuals
Food
processed at
compost
facilities
Landfills Wastewater
treatment
plants
Dairy
digesters
Municipal
food waste
digesters
Dth
Existing Projects
Near Term Projects
Medium Term Projects
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 141 of 1105
Total Potential Annual Production = 32 Bcf
ID RNG NREL Estimates
Source -Anaerobic MMBtu per Year
Landfills 3,712,221
6,196,531
20,220,571
-Separated Organics (Solid Waste)2,311,354
Total 32,440,676
National Renewable Energy Laboratory, NREL Biofuels Atlas
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 142 of 1105
RNG $ per Dth/MMBtu
Source: Promoting RNG in WA State
Avista Owned and Operated
ID -WA
2035 Premium
Estimate ($ / Dth)
RNG -Landfills $7 -$10
RNG -Waste Water Treatment Plants (WWTP)$12 -$22
RNG -Agriculture Manure $28 -$53
RNG -Food Waste $29 -$53
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 143 of 1105
Natural Gas IRP
A detailed level of RNG understanding and evaluation process will
be included in the Natural Gas IRP TAC #3 meeting on September
30, 2020
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 144 of 1105
Natural Gas Price Forecast
Michael Brutocao, Natural Gas Analyst
Second Technical Advisory Committee Meeting
August 6, 2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 145 of 1105
Henry Hub Expected Price Methodology
•Expected Henry Hub prices derived from a blend of forward
market prices on the NYMEX (as of 6/30/2020) and forecasted
prices from the 2020 Annual Energy Outlook (EIA) and two
consultants
2020 – 2022 2023 2024 2025 2026 – 2045
NYMEX 100%75%50%25%-
EIA/AEO -8.33%16.66%25%33.33%
Consultant 1 -8.33%16.66%25%33.33%
Consultant 2 -8.33%16.66%25%33.33%
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 146 of 1105
Henry Hub Expected Price and Forecast Blending
3
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 147 of 1105
Henry Hub Expected Price and Average Annual Forecasts
4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 148 of 1105
Stochastic Price Forecasting Methodology
•Evaluate a set of potential future outcomes based on the
probability of occurrence
–Expected Price used as the input
–At each period, random price adjustments follow a lognormal distribution
based on the Expected Price
•It is common practice to use lognormal distributions in forecasting prices as they have
no upward bound and should not fall below zero
•A single “draw” contains a set of unique price movements
•500 (electric) and 1000 (gas) draws were evaluated
5
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 149 of 1105
Sample Stochastic Price Draws
6
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 150 of 1105
Stochastic Price Draws
7
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 151 of 1105
Stochastic Prices (Results from 500 Draws)
8
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 152 of 1105
Levelized Stochastic Prices (Results from 500 Draws)
9
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 153 of 1105
Stochastic Prices (Results from 1000 Draws)
10
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 154 of 1105
Levelized Stochastic Prices (Results from 1000 Draws)
11
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 155 of 1105
Prices by Gas Hub (Henry Hub Expected Price + Basis)
12
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 156 of 1105
Levelized Prices 2022-2041
13
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 157 of 1105
Levelized Prices 2022-2045
14
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 158 of 1105
2021 Electric IRP
Regional Energy Policy Update
John Lyons, Ph.D.
Second Technical Advisory Committee Meeting
August 6, 2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 159 of 1105
Production and Investment Tax Credits
•Production tax credit $15/MWh adjusted for inflation
($25/MWh for 2019) for 10 years for wind construction
started by 12/31/20
•Investment tax credit for new solar construction drops
from 30% in 2019
–26% in 2020
–22% in 2021
–10% from 2022 onward
•Will be watching for any possible extensions with all of
the COVID-19 proposals
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 160 of 1105
State and Provincial Policies
State/Province No Coal RPS Clean Energy/Carbon Goal
Alberta Yes Yes Yes
Arizona No Yes No
British Columbia Yes Yes Yes
California Yes Yes Yes
Colorado No Yes Yes
Idaho No No No
Montana No Yes No
Nevada No Yes Goal
New Mexico No Yes No
Oregon Yes Yes Yes
Utah No Goal No
Washington Yes Yes Yes
Wyoming No No No
3
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 161 of 1105
Washington
•Clean Energy Transformation Act (CETA) SB 5116:
–No coal serving Washington customers by end of 2025
–Greenhouse gas neutral by 2030, up to 20% alternative
compliance
–2% cost cap over four-year compliance period
–100% non-emitting by January 1, 2045
–Social cost of carbon for new resources
–Additional reporting and planning requirements
–Highly impacted and vulnerable community identification
and resource planning implications
–Ongoing rulemaking in various stages for planning and
reporting
4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 162 of 1105
Washington
•HB 1257: Clean Buildings for Washington Act
–Develop energy performance standards for commercial buildings over
50,000 square feet (2020 –2028) “… to maximize reductions of
greenhouse gas emissions from the building sector”
–By 2022, natural gas utilities must identify and acquire all available cost-
effective conservation including a social cost of carbon at the 2.5%
discount rate.(Section 11 and 15)
–Natural gas utilities may propose renewable natural gas (RNG)
programs for their customers and offer a voluntary RNG tariff
–Building code updates to improve efficiency and develop electric vehicle
charging infrastructure
5
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 163 of 1105
Oregon
Executive Order 20-04
•New GHG reduction goal
–45% below 1990 levels by 2035
–80% below 1990 levels by 2050
•Directs 16 Oregon agencies to “exercise any and all authority
and discretion” to reach GHG reduction goals and “prioritize
and expedite” action on GHG reductions “to the full extent
allowed by law.”
•Agencies are working on rulemaking and implementation
SB 98
•Development of utility renewable natural gas programs
6
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 164 of 1105
2021 Electric and Natural Gas IRPs
Natural Gas & Electric Coordinated Scenario
James Gall/Tom Pardee
Second Technical Advisory Committee Meeting
August 6, 2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 165 of 1105
Scenario Goal
•Understand impact to electric resource planning if
customers switch from natural gas to electric service
•Scenario Proposal:
–By 2030: 50% of Washington Residential & Commercial
customers
–By 2045: 80% of Washington Residential & Commercial
customers
•Potential Scenarios:
–Hybrid natural gas/electric heat pumps
–Highly efficient technology allows for cold temperature space
heating
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 166 of 1105
Converting Natural Gas Load to Electric
Load
Natural Gas
(therms)TemperatureEnd Use Efficiency
Electric
Service Provider
Electric
(kWh)
3
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 167 of 1105
WA Res/Com Natural Gas Load Forecast
4
MD
t
h
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 168 of 1105
Customer Penetration Forecast
0.0%
10.0%
20.0%
30.0%
40.0%
50.0%
60.0%
70.0%
80.0%
90.0%
20
2
0
20
2
0
20
2
1
20
2
1
20
2
2
20
2
2
20
2
3
20
2
3
20
2
4
20
2
4
20
2
5
20
2
5
20
2
6
20
2
6
20
2
7
20
2
7
20
2
8
20
2
8
20
2
9
20
2
9
20
3
0
20
3
0
20
3
1
20
3
1
20
3
2
20
3
2
20
3
3
20
3
3
20
3
4
20
3
4
20
3
5
20
3
5
20
3
6
20
3
6
20
3
7
20
3
7
20
3
8
20
3
8
20
3
9
20
3
9
20
4
0
20
4
0
20
4
1
20
4
1
20
4
2
20
4
2
20
4
3
20
4
3
20
4
4
20
4
4
20
4
5
20
4
5
% Natural Gas Customer Reduction (WA Only)
5
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 169 of 1105
End Use Efficiency
0%
20%
40%
60%
80%
100%
120%
140%
160%
Water Heat Space Heat Process
Efficiency @ 5 Degrees
0%
20%
40%
60%
80%
100%
120%
140%
160%
Water Heat Space Heat Process
Efficiency @ 35 Degrees
Water Heat, 10.0%
Space Heat, 85.0%
Process, 5.0%
Water Heat, 30.0%
Space Heat, 60.0%
Process, 10.0%
Note: All efficiency conversion use a 10% efficiency benefit to electric
6
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 170 of 1105
Energy Conversion Factor
y = -3E-06x4 + 0.0007x3 -0.0438x2 -0.7097x + 259.49
R² = 0.9775
0
50
100
150
200
250
300
-20 0 20 40 60 80 100
Use
temperature
point
estimates
for
conversion
efficiency
Curve fit to
smooth out
steps
7
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 171 of 1105
WA Res/Com Natural Gas Load Forecast
8
MD
t
h
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 172 of 1105
Electric Peak Estimation Methodology
•Natural gas is typically daily nominations, while electric is
instantaneous.
–Hourly flow metering is available for some areas
•Sampled large gate-station hourly instantaneous natural
gas flow data
•Use sample data to estimate hourly natural gas load
from 2015-2019
•Estimate Peak-to-Energy load factor for each historical
month
•Use average monthly load factor for the peak adjustment
9
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 173 of 1105
Estimated Load Factors (2015-19)
10
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 174 of 1105
Hourly Electric Load History
-
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
5,000
Me
g
a
w
a
t
t
s
2015-2019 Control Area Load + WA LDC as Electric
CA Load + NG Control Area Load
11
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 175 of 1105
Eastern Washington Electric Service
Providers
EIA reported retail sales for 2018
Scenario assumes Avista will receive 75 percent of electric conversions
12
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 176 of 1105
Annual Conversion Load Forecast
-
100
200
300
400
500
600
700
800
900
1,000
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Annual Avg Peak
13
2020 IRP Forecast for 2030 absent fuel conversion:
Peak: 1,762 MW
Energy: 1,209 aMW
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 177 of 1105
2030 Monthly Load Forecast
-
50
100
150
200
250
300
350
400
450
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Energy Peak
14
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 178 of 1105
Scenario Analysis-Conversion Rates
0
50
100
150
200
250
300
-20 0 20 40 60 80 100
Current Technology
Hybrid Future
High Efficiency Future
15
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 179 of 1105
Scenario Analysis- Electric Energy
16
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 180 of 1105
Scenario Analysis: Electric December
Peak Load
17
Me
g
a
w
a
t
t
s
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 181 of 1105
Scenario Analysis: Natural Gas Demand
18
MD
t
h
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 182 of 1105
Next Steps
•Input into PRiSM model to determine resource
selection and cost
–Estimate cost meeting CETA requirements
–Estimate cost using least cost methodology
–Estimate emissions savings
–Estimate $/tonne
•Conduct electric resource adequacy study if time
permits
19
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 183 of 1105
2021 Electric IRP
Washington Vulnerable Populations &
Highly Impacted Communities
James Gall, IRP Manager
Second Technical Advisory Committee Meeting
August 6, 2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 184 of 1105
Identifying Communities or “Customers”
Highly Impacted
Communities
–Cumulative Impact Analysis
–Tribal lands
•Spokane
•Colville
–Locations should be available
by end of 2020
•State held workshops in
August & September 2019
Vulnerable
Populations
–Use Washington State Health
Disparities map
•What is disproportionate on a
scale of 1 to 10?
•Avista proposes areas with a
score 8 or higher in either
Socioeconomic factors or
Sensitive population metrics
–Should we include other
metrics to identify these
communities?
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 185 of 1105
Environmental Health Disparities Map
https://fortress.wa.gov/doh/wtn/wtnibl/
Department of Health data is divided up by Federal Information Processing Standards (FIPS) Code
3
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 186 of 1105
Environmental Health Scoring
From WA Department of Health
Circle areas match definition of
vulnerable population,
although access to food &
health care, higher rates of
hospitalization are not
expressively included but are
an indication of poverty
4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 187 of 1105
Selected Vulnerable Populations
5
Data is shown
by combined
score
Natural Gas
Biomass
Hydro
Wind
Solar
Kettle Falls CT
Kettle Falls
Little Falls Long Lake
Nine Mile
Palouse
Rattlesnake Flat
Adams Neilson
Northeast
Boulder ParkMonroe St
Upper Falls
Post Falls
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 188 of 1105
Spokane Area “Avista” Vulnerable
Populations
6
Data is shown
by combined
score
Natural Gas
Biomass/Other
Hydro
Wind
Solar
Waste-to-Energy (QF)
Upriver (QF)Boulder Park
BP Community Solar
Northeast
Monroe Street
Upper Falls
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 189 of 1105
IRP Metrics (From Last TAC Meeting)
Metric IRP Relationship
Energy Usage per Customer •Expected change taking into account selected energy
efficiency then compare to remaining population.
•EE includes low income programs and TRC based
analysis which includes non-economic benefits.
Cost per Customer •Estimate cost per customer then compare to
remaining population.
•How do IRP results compare to above 6% of income?
Preference •Should the IRP have a monetary preference?
•For example-should all customers pay more to
locate assets (or programs) in areas with
vulnerable populations or highly impacted
communities?
•If so, how much more?
7
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 190 of 1105
IRP Metrics (From Last TAC Meeting)
Metric IRP Relationship
Reliability
•SAIFI: System Average Interruption
Frequency Index
•MAIFI: Momentary Average Interruption
Frequency Index
•Calculate baseline for each distribution feeder and
match with communities
•Estimate benefits for area with potential IRP
distribution projects
•Compare to other communities as baseline
•May be more appropriate in Distribution plan rather
than IRP
Resiliency:
•SAIDI: System Average Interruption Duration
Index
•CAIDI: Customer Average Interruption
Duration Index
•CELID: Customer’s Experiencing Long
Duration Outages
Resource Analysis •Estimate emissions (NOX,SO2, PM2.5, Hg) from
power projects located in/near identified communities
•Identify new resource or infrastructure project
candidates with benefit to communities; i.e. economic
benefit, reliability benefit
•Identify how resource can benefit energy security
8
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 191 of 1105
Energy Use Analysis Results
•Uses five years of customer billing data
•Median income over the same period is used to estimate
affordability
•Separated electric only vs electric/gas customers
–Future enhancement include single/multi family homes, and
manufactured homes
9
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 192 of 1105
Energy/Cost Analysis
Electric Only Customers
Natural Gas/Electric Customers
Note: Combined natural gas/electric homes have higher energy burden due to
fewer multifamily homes included in the population or all electric home including
homes with alternative heat such as wood, propane, oil, pellets. Future analysis
needed to validate this hypothesis.10
Area Fuel Type Energy Use Avg Bill Income % Income
Vulnerable Population Areas Electric 820 KWh $80
Other Areas Electric 875 KWh $84
Vulnerable Population Areas Gas 52 Therms $47 $44,889 3.4%
Other Areas Gas 62 Therms $56 $68,250 2.5%
Area Fuel Type Energy Use Avg Bill Income % Income
Vulnerable Population Areas Electric 998 KWh $98 $42,730 2.8%
Other Areas Electric 1,010 KWh $100 $58,834 2.0%
Note: Mean energy use is statistically significantly different when removing energy use data below 100 kWh per month (1,049 kWh vs 1,082 kWh)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 193 of 1105
Vulnerable Populations
Electric Only Customers-Energy % of Income
11
Spokane Area
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 194 of 1105
Vulnerable Populations
Gas/Electric Only Customers-Energy % of Income
12
Spokane Area
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 195 of 1105
Reliability Data- CAIDI
Measure of resilience-minutes of outages per event
Excludes Major Event Days (MED)
13
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 196 of 1105
Reliability Data-CEMI
Measure of reliability-Events per Customer
14
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 197 of 1105
Vulnerable Area vs Non Vulnerable Areas
Vulnerable Areas
Non-Vulnerable Areas
CAIDI CEMI
15 Note: 5 yr Average differences are statistically significantly different
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 198 of 1105
CAIDI- By Feeder Type
Note: Avista has no
vulnerable areas with urban feeders
16
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 199 of 1105
CEMI- By Feeder Type
Mixed Feeders
Vulnerable Areas
Non-Vulnerable Areas
Rural Feeders
Vulnerable Areas
Non-Vulnerable Areas
Note: Avista has no
vulnerable areas with urban feeders
17 0.0
1.0
2.0
3.0
4.0
5.0
2015 2016 2017 2018 2019 5 yr Avg
Ev
e
n
t
s
Suburban Feeders
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 200 of 1105
Avista’s Washington Power Plant Air
Emissions
-
0.5
1.0
1.5
2.0
2.5
3.0
2015 2016 2017 2018 2019
Washington NOx Emissions
-
0.005
0.010
0.015
0.020
0.025
0.030
2015 2016 2017 2018 2019
Washington SO2 Emissions
-
0.00001
0.00001
0.00002
0.00002
0.00003
0.00003
0.00004
0.00004
0.00005
0.00005
2015 2016 2017 2018 2019
Washington Hg Emissions
-
0.050
0.100
0.150
0.200
0.250
0.300
2015 2016 2017 2018 2019
Washington VOC Emissions
18
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 201 of 1105
TAC Input
•What other metrics can we provide in an IRP to
show vulnerable populations and highly
impacted communities are not harmed by the
transition to clean energy
19
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 202 of 1105
Second Technical Advisory Committee Meeting, Thursday, August 6, 2020
Virtual Attendees: James Gall, Lori Hermanson, John Lyons, Tom Pardee, Rachelle
Farnsworth, Greg Nothstein, Dainee Gibson, John Chatburn, Mike Morrison, Terri
Carlock, James McDougall, Michael Brutocao, Paul Kimball, State of Idaho (x2), Steve
Vincent, Nikita Bankoti, Chip Estes, Joana Huang (UTC), Terrence Browne, Leona
Haley, Jody Morehouse, Scott Kinney, Corey Dahl, Katie Pegan, Sellers-Vaughn
(Casc); Joni Bosh, Devin McGreal, Vlad Gutman-Britten; Steven Simmons, Jennifer
Snyder, Morgan Brummund, Max St. Brown (OPUC), Jorgen Rasmussen, Jorgen;
Heutte, Fred Heutte (NWEC); Sudeshna Pal (CUB), Brian Robertson, A. Argetsinger,
Guest (18), Kaylene Schultz, Grant Forsyth, Anna Kim (OPUC), Dan Kirschner, Katie
Ware, Matt Nykiel, Ken Ross, Ashton Davis, and Steve Johnson (UTC).
Notes in italics are short responses from the presenters and notes with brackets [ ] and
times after them were pulled from the chat function on Skype.
Introductions and IRP Process Updates, John Lyons
Matt Nykiel: What is the study request deadline for gas?

Tom Pardee: No formal deadline. Feel free to forward to me. We will be running gas
models after this meeting and they will presented at TAC 3. Gas will show CPA results at the November meeting, but will share some things earlier such as measure list. Natural Gas & Renewable Natural Gas Market Overview, Tom Pardee
Matt Nykiel: Since Avista gets a lot of gas from Canada, how is legislation impacting
pricing and imports? Do you have general thoughts on this?
Tom Pardee: Haven’t heard of that. Wood-Mac does include legislation in their
fundamentals based forecast. What does the legislation entail? Matt Nykiel: Carbon tax on gas essentially. How is this impacting the market in Canada
and what we get from them, the reverberating impacts to price? It is important to keep
on our radar as we’re evaluating for Avista.
Tom Pardee: Yes, British Columbia has a carbon tax. We will look into this specifically
and get back to the TAC. Fred Heutte: Thanks for a very thorough survey. What are you seeing in near-term gas prices in 1, 2, 3 years due to COVID? Rig counts are dependent on early production in particular for Canadian short-term. There are a lot of ways it could go. Tom Pardee: Canada has the lowest marginal costs for natural gas. There are a lot of
liquids, not specifically drilling for natural gas but for oil so they need volumes to offset the high capital. They have a low break-even cost and so much capital is already invested, so they’ll be slower to react to pricing changes than the northeast and the US.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 203 of 1105
For oil or bitumen, they are based on the breakeven cost for liquids and oil. Dry gas is mostly about getting that out as cheap as possible. Fred Heutte: That is helpful. Is Avista broadly speaking, sourced more from Alberta or
BC? What is going on in the Canadian Basin? Tom Pardee: Alberta is mostly liquids and BC, Motney, etc. is dryer. Broadly, Avista is
AECO mostly.
Fred Heutte: So, not as much as Sumas. Thanks.

Nikita Bankoti (Slide 16, US demand): That is a lot of information to process. Seems
to be increases in LNG exports, will Avista be procuring more LNG?

Tom Pardee: Across all areas across all sectors, if you take away LNG exports, it’s
mostly staying the same. If gas started coming in large increments from Canada, that’d
have a huge impact on us since we get 90% of our supply from Canada. In the US
everything is hedged financially at Henry Hub. Simple supply – Canada is king around
here, gas is cheap. Alberta is main economic driver, at least 50%. If there were an
issue, it’d come from Alberta. Does that help?
Nikita Bankoti: Yes, thank you so much.
Steve Johnson: To reduce to a more simple understanding, most of the growth in
demand will be from LNG exports.
Tom Pardee: Yes, that’s a fair statement.
Steve Johnson: There’s a lot of LNG exporters in the world. The US will become the
number one exporter if all of these planned projects come to fruition. The cost for gas
here rises and negatively impacts LNG going forward. Most investors think gas prices
will stay low, therefore LNG goes forward which relieves upward price pressure on gas.
Focus on other side of the equation if LNG gas projects here go forward. Tells me a lot
of dollars think prices stay very low since if they go up projects won’t happen.
Tom Pardee: The cheaper oil is, the less likely LNG exports are wanted around the
world. Can they burn bunker oil? If oil goes high, then more demand for LNG. These are
often compared. If oil price is high, there is more demand for LNG exports. That is
where LNG comes in. History of LNG is tied to oil so oil price dictates the LNG price.
Now the linkage is broken and LNG is not as tied to oil as it was formerly. Now a LNG rate is Henry Hub plus. If oil is expected to go up, then my guess is there’d be more LNG. If oil goes up to $120 a barrel, a lot more LNG is cheaper. Steve Johnson: One can expect gas to remain flat?
Tom Pardee: Yes. Regardless of LNG exports.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 204 of 1105
Nikita Bankoti: What is MSW? Municipal solid waste.
Fred Heutte: Wonder if you have been following Oregon AR632 docket for Northwest
Natural RNG policies? Tom Pardee: Yes, we have had members go to every AR632 rulemaking. We were a
part of that. Trying to understand what the policy means. The gas side will have a more detailed overview. I’m not an RNG expert. If you have better information into RNG price
on the east side you are always welcome to come over to our TAC.

Fred Heutte: Interesting info.

Jody Morehouse: Open rulemaking for SB passed 2 weeks ago in Oregon and were
adopted 7/31/20. Will cover more in September TAC.

Nikita Bankoti: The Commission has an ongoing docket under UG-190818 for the
Washington RNG Staff investigation.
Kathleen Kinney: Market pricing in the $10 - $12 range for RNG is doable. Utility is
able to offer a consistent long-term price.
Kathleen Kinney: Comments via RNG; for market pricing $10-12 price is doable. If
Utilities can offer a long-term prices that’s something that producers are looking for.
Another option, I haven’t seen done in person is to buy LNG at a relatively low fixed
costs until the LNG purchase requirement kick in and be able to sell long term when
policies kick in. Avista can take advantage of that margin in the near-term. Again, I’m
certainly willing to connect after this.
Matt Nykiel: I could use a refresher in terms of how gas impacts customer rates and
how that is impacted through the price cost adjustment. How is the price set and passed
on if higher or lower?
Tom Pardee: Within an LDC. You probably get cheap gas. Projected rate, say it’s a
dollar comes in higher, then in future rates, we’d charge more. Lower is passed through
against rate projection for the future. Pass through at the cost of gas, but procurement
charge with no markup. What we buy gas for is what we sell gas to customers for with
no mark up. Optimization for Jackson Prairie or transport is for customers and goes
against rates. If we sell gas for $50,000 premium in the market, it goes against rates to
offset the commodity rate for overhead. PGA, or purchased gas adjustment is set on November 1st. How accurate you were on every November 1st is adjusted. If too high now, it reduces rates later. It is an accounting deferral balance. Matt Nykiel: Thanks so much, appreciate the refresher.
Natural Gas Price Forecast, Michael Brutocao
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 205 of 1105
Ben Otto: Can you tell us who the consultants are?
Tom Pardee: One is Wood-Mackenzie and the other is CERA. They are both well-
known and respected within the gas industry. We put out this way so we don’t have to get their approval which is difficult. Ben Otto: This highlights our concerns. It is a public process, but having stuff we can’t
comment on specifically is concerning.
Dan Kirschner: Nominal dollars? Yes.

Nikita Bankoti: Why is there a difference in percentages used? What is the reason for
blending and the mix across the years?

Michael Brutocao: Wouldn’t want to assume one is more accurate than the other.
Significant deviations in NYMEX more than accounts for risk and overtakes what you’d
expect the nominal prices to be.
Nikita Bankoti: For 2023 weighting, why is NYMEX weighted more than the
consultants? Due to standard deviation?
Tom Pardee: So for historic measures, NYMEX in the near term is the best indicator of
everything that all traders know on that date. Fundamental forecasts take months.
NYMEX changes daily and is the most up to date pricing with fundamentals. NYMEX
actively trades about three-ish years out – it becomes a lot less liquid the further out you
go. Further out is less liquid so you really don’t know what the price is the further out
you look.
Steve Johnson: Can I ask a follow up question? I recall these charts in the past IRPs.
Three year forecast based on forwards or combination, then we take consultants with
the forwards, update every IRP with the same upward trend further out with the same
consultants. I’m not on board as we never seem to see these upward trends. It’s the
trends I’m not believing in. Will have to drop off in 10 minutes, but will circle back with
the team on this topic.
Sudeshna Pal: Is there any visibility into the forecast models and discussion into the
drivers and what is causing the trends? What are the drivers of this forecast?
Tom Pardee: Time. Known elements when putting the forecast together. For example,
one forecast may have COVID included, but an older one might not. Individual assumptions and guessing about what may happen and when and how those impact prices. The further out you go, no one is going to be right, but they have people that look at these issues. No one is going to be right.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 206 of 1105
Ben Otto: Past two questions highlights the need to see these assumptions. Customers
end up paying for this. Important so we can see and understand. The best practice is to disclose these forecasting techniques to understand them. Fred Heutte: Gas future prices, NYMEX forward strip and the longer term by various
consultants. NYMEX market for today is over $2 at Henry Hub. Really liquid and a good indicator. It is the largest in the world at about $1 trillion a year, but it doesn’t go out far. Starts with 126,000 September contracts, but down to 7,000 by February, and at 18 months almost none. Further out less and less trades yet they report prices all the way
out to 2032. Out to 18 months is very good. Longer term forecast basically take the
same view – we’ll have as much shale gas as we need forever. We don’t know the
underlying production cost. Prices have been on average over the prices over the last
many years. What happens if the industry consolidates? The Wood-Mac and IHS
consultants are really smart, doing the best they can. We don’t have anything better
than long term forecasts. What is the upside price risk – that is the question. Make sure
to run a high price gas forecast if that comes to pass which is what the IRP is supposed
to address.
James Gall: Appreciate the comments on the scenarios we do, which often don’t get
the focus they deserve. It is important to consider the scenarios from IRP to IRP. There
are differences in resource choices. This topic has a lot of interest.
Nikita Bankoti (slide 9): Is there a reason there’s more gas draws than electric? I
believe it is less, but am not 100% sure. What’s the reason behind that? Tom Pardee: We do more gas draws because we can. We model on a daily basis. We
have a smaller daily model than electric, which is modeled hourly. Ours doesn’t take as
long to model. One or two days per run, and week on the electric side for one scenario
with 500 distribution draws.
Nikita Bankoti: OK, that makes sense.
Kathleen Kinney: Curious about the higher scenario above the $10-12 (tying into
RNG), is there some way to use extended RNG contracts to take out the risk?
Tom Pardee: It is something we can consider because you’re definitely taking some of
the risk out with RNG. There is a major risk of not being able to get supply. Take risk out
of a transportation pipeline. There was the explosion a few years ago on the west side.
Cost risk, loss risk and how much RNG can take off the board.
Kathleen Kinney: It would have to be a long-term contract. Fred Heutte: Two comments. Run another version of this gas price and market price
looking at a peak of $3 shown. What about a peak of $4 with consolidation and a lower rig count? With lower supply, prices go up. Delivery risk and questions raised by that.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 207 of 1105
explosion and compressors. Has Avista looked at the risk involved with your main supply coming down from Alberta, which is very reliable? Have you looked at this risk? Tom Pardee: Yes, we’ll talk more about supply risk from major locations at TAC 3. We
do look at it and there will be specific sensitivities around this. Ben Otto: 100% or 90% of gas from Canada. Risk should focus on this and not
necessarily on the hubs since all supply comes from Canada. Previously you’ve shown you only use Canadian supply.

Tom Pardee: We do use the other supply areas, although not as much. Where we have
supply from is number 1 at AECO, number 2 at Sumas for peak and Jackson Prairie,
and number 3 from Rockies for peak and Oregon. Each of these we look at to restrict or
take out of the model to understand. In the overall portfolio, Rockies in about 1-in-10
situations.

Upstream Natural Gas Emissions, Tom Pardee Tom Pardee: Upstream emissions are natural gas emissions that occur prior to the
point of combustion. Mike Morrison: When computing Global Warming Potentials, what were the residence
times assumed for each gas? How long are they assumed to remain in the
atmosphere?
Tom Pardee: 1 element of carbon, 1 factor of CH4 equal to 34. Continues to grow
(NOx) in the 100 year potential.
Kathleen Kinney: CH4 degrades to CO2 near-term emission and decreases as it
degrades over time.
Fred Heutte: I’m certainly not an atmospheric chemist. CO2 not very interactive
whereas methane is very interactive. For CO2, half is taken up in a year into trees,
ocean, and vegetation and the rest is over 1,000 years – impact is long. Methane –
because it’s interactive – it’s in the atmosphere for 10-12 years and gone in 20.
Nikita Bankoti: Is this a recent EP estimate?
Tom Pardee: 2020.
Dan Kirschner: April 2020 – considers through 2018. [8/6/2020 12:44 PM] Steven Simmons: https://www.nwcouncil.org/energy/energy-
advisory-committees/natural-gas-advisory-committee (https%3a//www.nwcouncil.org/energy/energy-advisory-committees/natural-gas-advisory-committee) link to Northwest Power & Conservation Council work on methane & NGAC
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 208 of 1105

Fred Heutte: We will be submitting comments in writing to Avista on this topic and won’t
belabor the point here. We are concerned with the emissions factor in the US and Canada. The EDF project has been working on this issue for better than a decade. Scientists and analysts in the US, the council adopting their low emissions rate in the
US. The problem with the Canadian sources is they are based on old data. Recent
publications in peer reviewed journals will show this. Reasonable data for US-sourced
gas, but not Canadian-sourced gas which hasn’t been updated.

Dan Kirshner: We have a bit of a different perspective than Fred and will provide our
comments to the council. We support the regional approach Avista is taking as opposed
to national averages. Puget Sound Clean Air Agency and the Port of Kalama data are
government sponsored and is sufficient and a good approach for Canada. We disagree
with NWEC for the Rockies. EPA has an annual update for Rockies. Each year is
appropriate in that regard. Will send a letter regarding this. There are different
perspectives on this.
Tom Pardee: Thanks Fred and Dan. The problem is Avista is not an expert on this
upstream emissions issue, but we have some expertise. Fred Heutte: We’re not experts. Canadian FIMSA (0.78). It’s like pricing. You do as
best as you can. Appreciate there’s different perspectives. Power Council – we feel
this is the appropriate factors.
[8/6/2020 12:49 PM] Vlad Gutman-Britten: It would be useful to include at minimum a
sensitivity with a higher leakage rate to understand the impact of that choice on
resource selection.
Tom Pardee: We could do this as Dan mentioned to show sensitivity. If we were to use
2.3% for Rockies, it doesn’t impact much because of how little gas we have from
there. Scenarios will likely address some of this. One scenario will be to change this fraction. [8/6/2020 12:50 PM] Vlad Gutman-Britten: For example using EDF's number. Yes.
That would allow stakeholders to evaluate how important/not important this factor is. Thanks very much for your consideration.
[8/6/2020 12:52 PM] Ben Otto, ICL: Agree with Vlad. For any uncertain forecast it is
good practice to assess a range of scenarios. Fred Heutte: Some Canadian numbers are really dated and minor updates in the last
20 years.

Regional Energy Policy Update, John Lyons
Investment and production tax incentives:
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 209 of 1105
PTC $15/MWh (base) for 20 years for wind started by 12/31/20
ITC for solar drops 30% in 2019, 26% in 2020, 22% in 2021, 10% from 2022 on
ITC for battery storage if filled with solar
[8/6/2020 12:57 PM] Vlad Gutman-Britten: On the incentive side, are you considering
Washington state sales/use tax incentives for RE sited in the state?
James Gall: Yes we include those incentives in our Generating Resource Assumptions
sheet.
[8/6/2020 12:58 PM] Snyder, Jennifer (UTC): I thought New Mexico passed a clean
energy law. Am I mistaken? Vlad Gutman-Britten: Yes.
Fred Heutte: Will put a link in the chat re: modeling this in Aurora from yesterday’s
NPPCC meeting. Here's the NW Council presentation and the spreadsheet. These are downloads from the Box file sharing service:
• https://nwcouncil.app.box.com/s/s2whne2t77a1qxpm17qtz5aorwuksjil
• https%3a//nwcouncil.app.box.com/s/s2whne2t77a1qxpm17qtz5aorwuksjil)
• https://nwcouncil.app.box.com/s/po27u2275z0cuanuix6oucnw7luz62bk
• https%3a//nwcouncil.app.box.com/s/po27u2275z0cuanuix6oucnw7luz62bk)

[8/6/2020 1:03 PM] Fred Heutte (NWEC): And the System Analysis Advisory
Committee web page is here: https://www.nwcouncil.org/meeting/system-analysis-
advisory-committee-webinar-august-5-2020
https%3a//www.nwcouncil.org/meeting/system-analysis-advisory-committee-webinar-
august-5-2020)
Ben Otto: Back to tax credits slide. PTC could be charged to storage if charged with
renewable. For this IRP will there be basic market power storage and renewable.
James Gall: We modeled both and treated the PTC correctly. Both technologies were
selected. One bundled with storage and selected. Storage as a standalone resource
with the credit. Both were selected.
[8/6/2020 1:05 PM] Rachelle Farnsworth: What happens to costs above 2%, and
costs for Colstrip that could occur after 2025?
James Gall: Colstrip costs from a CETA perspective. The 2% cost gap not applicable to
Colstrip since it’ll be fully depreciated by 2025
Vlad Gutman-Britten: I don’t believe the statute says for “new” resources. Can you
explain your interpretation?

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 210 of 1105
James Gall: Two instances 1) you’re correct, 2) for new resource decision-making.
Matt Nykiel: Can you talk more about how the social cost of carbon was analyzed –
fixed or variable cost? James Gall: Planning on modeling social cost of carbon similarly to the expected case
in the last IRP. Model plant’s dispatch of real-time operations – new resources would include construction and operations costs of emissions (shared at last TAC meeting). Will be included in the optimization used to determine the least cost options. DR will be
assigned an emission benefit. Scenarios will be run for the Idaho portion to understand
the social cost of carbon implications for Idaho customers.

Nikita Bankoti: The Commission needs to update the social cost of carbon costs, it
should be updated and on the website [WUTC] soon.

Matt Nykiel: Is Avista treating SCC as a fixed or variable cost.
James Gall: Variable. There’s a price that’s fixed (construction) but also variable cost
assigned to operations.
Matt Nykiel: Can you clarify “analyzing social cost of carbon for Idaho”, clarify the
difference. I’m not totally taking up what you are putting down for Idaho. James Gall: The social cost of carbon is included for Washington as required by law.
Scenarios for that cost for Idaho. Will discuss at next electric TAC. For the variable cost,
the price [per metric ton] of the social cost of carbon is fixed for each year, but the total
cost is variable each year with the amount of emissions plus the emissions from
construction. For Washington, it is in the expected or base case and as a scenario for
Idaho.
[8/6/2020 1:12 PM] Fred Heutte (NWEC): Clarification from Joni: Hi all, Joni asked
me to pass this along (she can add more via the phone): the 2045 standard is for non-
emitting and RE.

Sec. 5. (1) It is the policy of the state that nonemitting electric generation and electricity
from renewable resources supply one hundred percent of all sales of electricity to
Washington retail electric customers by January 1, 2045. By January 1, 2045, and each
year thereafter, each electric utility must demonstrate its compliance with this standard
using a combination of nonemitting electric generation and electricity from renewable
resources. Natural Gas and Electric Coordinated Study, James Gall and Tom Pardee
James Gall: Potential scenarios – it would be helpful to have input on these; are these
the right scenarios to look at?
Fred Heutte: Heating and cooling, are you also looking at water heating?
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 211 of 1105
James Gall: Yes, we will get to that in a minute.
Kathleen Kinney: On the 10% efficiency, can you explain that more, is that a benefit to
electricity?
James Gall: We’re making assumptions of how folks will convert. We’re reducing
conversions by 10% in case we missed some efficiency benefits. More biased to electric.
Fred Heutte: Have you been following Power Council and their load forecast? Are you
looking at a climate adjustment to the forecast for the substantial increase in late
summer demand?
James Gall: Yes. That is a great question for the next meeting, it will probably be a
topic at the next TAC.
Fred Heutte: Detecting a theme – lots of interesting stuff at the next meeting.
Kathleen Kinney: What portion are you assuming are heat pumps (of converted)?
James Gall: Most gas to electric is to heat pumps.
Kathleen Kinney: Is there a lower efficiency scenario too? Not everyone is going to
convert to heat pumps.
James Gall: A lot of that can be derived from showing the efficiencies at various temps.
Dan Kirschner: Baseboards are 100% efficient at site. Are you assuming at site?
James Gall: This is at the site. When building generation, we’ll have to adjust for
losses.
Jennifer Snyder: Baseboard versus heat pump idea, if someone were thinking of going
from gas to electric, most people wouldn’t go from gas to baseboard.
James Gall: Conversions currently using furnaces are often ducted or point source
heat. Homes with ducts will likely convert to heat pump. Those using point sources will
use a mix and it’s tough to determine the mix of baseboard to heat pumps.
Nikita Bankoti: Very drastic change in period, more energy use at peak, you’ll be using
a lot of different resources, will customers be charged a higher rate?
James Gall: Because of added load in the winter, what is the impact to customers?
The IRP process will illustrate the cost impact as compared with the expected changes
and also look at what the customer is avoiding on the gas side. Please look at the last
IRP where we did a similar analysis. Cost is higher, emissions are lower. Will the
customer be paying more? Will depend on price of power, environmental policies, and
conversion costs (customer-borne). Lastly, we also need to address impacts on T&D –
large conversion to electric will likely require T&D incremental infrastructure costs. We may not be able to address that in this IRP.
Vlad Gutman-Britten: Sorry, missed the first chunk of that. The idea of extra load
needs to be served with long-duration storages. CCS and RNG that can fill in that role
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 212 of 1105
Studies show that you can fill in the role without long-term storage. Are you looking at space and water heating?
James Gall: Looking at all end uses – water, space, process.
Vlad Gutman-Britten: In calculating peak are you incorporating latest codes?
James Gall: Yes we’re trying to estimate what the peak is, then when we pick
resources, the type of program that would reduce peak if cost effective.
Vlad Gutman-Britten: Incorporating that type of resource? Yes.
Jennifer Snyder: Are you modifying this within the CPA’s technology potential?
James Gall: Yes, since increasing the amount of water heaters on the system.
Kathleen Kinney: Could it be looked at with a cost comparison using RNG to achieve
the same emissions goal?
James Gall: Yes. Tom will have scenarios. My side will show electric and comparing
both we can come to a conclusion. Advantage of gas/electric IRP at the same time – we can look at both.
Fred Heutte: Glad water heater load management is already addressed. With new
cross sector load on the section including electrification, if that load can be managed, it
should be. To what degree have you looked at managing space heat?
James Gall: Through the CPA. Look at manageable savings we can get from our
existing load and how does that apply to this situation.
Ben Otto: Along with DR, applies to space heating load, applying a package of building
shell improvements is another way to address this issue.
James Gall: We will look to AEG for this and work with the CPA to incorporate.
Jennifer Snyder: Depending on how much you can do this in your CPA, electric house
has ability to be made tighter than gas heated house. Don’t know if that will make a
difference or if it can be captured in a CPA. Will have to get back to the group on this.
Kathleen Kinney (slide 15): I’m confused, I’m looking at the graph and it looks like
higher is more efficient.
James Gall: Less efficient the higher you go on the Y axis. More kWh used per Dth
replaced.
Sudeshna Pal: What is the current technology?
James Gall: Slides 6-7, the Base Case we already shared using current technology to
estimate future loads using more efficient technology in the future. Hybrid uses gas and
electricity more efficiently with existing technology.
[8/6/2020 2:24 PM] Vlad Gutman-Britten: I think we'll have comments on some of the
end use efficiency assumptions, but will provide those in writing.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 213 of 1105
Mike Morrison (Slide 15): Dth to kWh is about 293, so what you are saying is the
hybrid future is 6 times as efficient? James Gall: That is not what this is showing at the amount of gas in the base scenario.
We’re using electric not gas. Trying to illustrate how much gas demand will go to electric. This may not be the best way to show that. We start with this track, but converting with simplifying, we remove space heat from the calculation. Efficiency components are multiplied to those end uses.
Mike Morrison: Ok, so this is only in the context of the conversion you are doing. It
seems very complicated, you might have done it a simpler way.

[8/6/2020 2:28 PM] Steven Simmons: Have you thought about what might be the
implications on the gas system in these scenarios - especially the hybrid system where
you are relying on gas solely for peak days. More gas storage?

Tom Pardee: Will come out in the scenarios; maybe RNG can take some of this risk off
the system. Will circle back to the electric TAC to show the results of modeling this on
both sides.
Highly Impacted & Vulnerable Populations Baseline Analysis, James Gall: Nikita Bankoti: Interesting to understand if company will use a map or delve into
individual household data. Interesting that resources are in these neighborhoods. What
does the company plan to do in this area regarding equity and community engagement?
Are you considering any factors and pollution burden for these indicators? James Gall: At this time, we haven’t looked at those two items yet because it’s outside
of the law. The expectation is areas may be added, but we didn’t want to go down that
path until we get an indication from the state regarding these areas. May have low
income in areas that aren’t necessarily impacted. We have low income programs
broader than these areas. Look at how the law is written – what these areas look like
today versus the future. That’s where we’re focusing right now. Looking to include these
populations in future IRPs as well as maybe programs to address these areas. There
are limited things an IRP can do. Where does the IRP apply and where do other
processes apply?
[8/6/2020 2:47 PM] Vlad Gutman-Bittmen: Given that the statute emphasizes health, I
assume you mean locating non-emitting assets in identified communities? Just a note
that not all resources that are "clean" under CETA are clean from a health perspective,
like biomass for example, but understand your point. Thank you. James Gall: Correct.
Max St. Brown: Lot of overlap with what we’re doing for COVID and what customers
are being impacted. Is this process of linking marketing data to customer data being documented?
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 214 of 1105
James Gall: No we ended up using census data for the most past and not the
marketing data.
Lori Hermanson: Trove purchases data from 27 different parties and compiled income
data. We ended up using census data because the data was substantially different. Nikita Bankoti: If you have data on average household size, can that be used?

Grant Forsyth: Yes there’s average household size from the American Community
Survey. It doesn’t go very far back, seems to be volatile and has been smoothed so
much it has little variation over time. It is somewhat difficult data to work with unless you
use a 5-year moving average. You can get it down to the tract or block level, but can
you do any time analysis? 3 – 5 year average smooths things out a bit and causes
problems.

[8/6/2020 3:00 PM] Griffith, Kate (UTC): Are you able to see how this changes in
summer or winter months?
James Gall: No, only annual data is available. Will probably be a future analysis to see
from a heating versus air conditioning point of view.

Nikita Bankoti: Not a question. Just thinking if it will be easier to access and analyze
population density data (in vulnerable areas) instead of household level data.

Vlad Gutman-Britten: Is the reason for the shorter outage in vulnerable areas because
they’re urban?

James Gall: Yes, more vulnerable populations are in suburban areas. Being in the
mixed vulnerable and not vulnerable areas takes more time driving to them to fix the
outage.

Vlad Gutman-Britten: Not being accusatory, but it is not accurate to say vulnerable
areas are receiving a more resilient service because it is just in an urban area that is
easier to service?

James Gall: Wouldn’t go that far yet. The only ones that are less are rural areas. These
are very rural areas and if the analysis is by customers per mile this may be the case. It would require more analysis and this may be the next step. Vulnerable areas seems to have more reliability in urban areas.

[8/6/2020 3:14 PM] Vlad Gutman-Britten: Controlling resilience for customer density
does seems like a useful metric to develop to identify discrepancies. If they exist.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 215 of 1105
[8/6/2020 3:15 PM] Vlad Gutman-Britten: Will you resend the deck with new slides
please? [8/6/2020 3:15 PM] Yes, we will. Either later this week or early next at the latest.

[8/6/2020 3:18 PM] Ben Otto, ICL: Rathdrum gas power plant in Idaho is very close to
the Washington border. Is this included?
James Gall: No, it is not included in this study being it’s in Idaho.

[8/6/2020 3:19 PM] Vlad Gutman-Britten: I'm assuming this is assuming that pollution
harms accrue near a facility? This isn't based on a pollution transport model? What
about identified community down-wind even if they’re not close to a facility.
James Gall: Haven’t gotten down to that level. CS2 in Oregon and several CCCTs,
Rathdrum, Colstrip, etc. and limited thermal generation in eastern Washington. This is
really only what there is in Washington.
Fred Heutte: Not that I’m an expert, but there is a good study on this from Portland
State. When you look forward to where the EV infrastructure can be placed, this is something we should consider forward-looking. [8/6/2020 3:24 PM] Vlad Gutman-Britten: These strike me as good metrics, but I'm
not sure the folks on the phone are necessarily well positioned to answer. That may require proactive outreach to groups active in some of the communities you identified, as well as Front & Centered. Fred Heutte: CIMS or other data. Make sure to note where the data is coming from for
these studies. Ben Otto: Super fascinating. Really good work. We’d encourage Avista to apply the
same thinking to Idaho. Just the right thing to do. Aligns with your corporate
commitments.

Vlad Gutman-Britten: Agree, its great work.

Ben Otto: This presentation has helped me understand the right questions to ask.

Nicholas: The OPUC breakout is by area (block group) of the vulnerable population.
One point of verification. Understand it as break out by area as being broadly, rather
than by meter.
James Gall: Characterized by geography. Meters in an area, but not identified if a
particular customer or not. Not necessarily every customer in that area is vulnerable.
Remind ourselves not to focus on geography when developing programs.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 216 of 1105
Nicholas: Right. Thank you. Wanted to make sure. It is a challenge.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 217 of 1105
Economic, Load, and Customer Forecasts
Grant D. Forsyth, Ph.D.
Chief Economist
Technical Advisory Committee Meeting
August 18, 2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 218 of 1105
Main Topic Areas
•Service Area Economy
•Long-run Energy Forecast
•Peak Load Forecast
•Long-run Gas Customer Forecast
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 219 of 1105
Service Area Economy
Grant D. Forsyth, Ph.D.
Chief Economist
[e-mail]
3
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 220 of 1105
Distribution of Employment, 2019
Source: BLS and author’s calculations.4
Private
Goods
14%
Private
Services
70%
Government
16%
Avista WA-ID-OR MSA
Private
Goods
14%
Private
Services
71%
Government
15%
U.S.
Federal
11%
State
20%
Local
69%
Avista WA-ID-OR MSA Government
Federal
12%
State
23%
Local
65%
U.S. Government
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 221 of 1105
Non-Farm Employment Growth, 2009-2020
Source: BLS, WA ESD, OR ED and author’s calculations.
-16%
-14%
-12%
-10%
-8%
-6%
-4%
-2%
0%
2%
4%
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.
Non-Farm Employment Growth (Dashed Shaded Box = Recession Period)
Avista WA-ID-OR MSAs U.S.
Service Area employment level
same as 2013/14 period.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 222 of 1105
MSA Population Growth, 2007-2019
Source: BEA, U.S. Census, and author’s calculations.
1.6%
1.2%
0.9%
0.7%
0.5%0.4%
0.7%
1.0%
1.2%
1.6%1.6%
1.5%1.5%
1.0%0.9%0.9%0.8%
0.7%0.7%0.7%0.7%0.7%0.7%0.6%0.5%0.5%
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
An
n
u
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l

G
r
o
w
t
h
Population Growth in Avista WA-ID-OR MSAs
Total WA-ID-OR MSA Pop. Growth U.S. Growth
2008-2012: Employment
Growth Slowing = Slowing
In-migration
2013-2019: Employment
Growth Increasing =
Increasing In-migration
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 223 of 1105
GDP Growth Assumptions: 2021 IRP vs. 2020 IRP
7 Source: Various and author’s calculations.
-8.0%
-6.0%
-4.0%
-2.0%
0.0%
2.0%
4.0%
6.0%
2020 2021 2022 2023 2024 2025
An
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l

G
r
o
w
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h
Average June 2019 Forecast Current Forecast Average
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 224 of 1105
Long-Term Energy Load Forecast
Grant D. Forsyth, Ph.D.
Chief Economist
[e-mail]
8
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 225 of 1105
Basic Forecast Approach
2020
Time
2025 20452026
1)Monthly econometric model by
schedule for each class.2)Customer and UPC forecasts.
3)20-year moving average for “normal
weather.”
4)Economic drivers: GDP, industrial
production, employment growth,
population, price, natural gas
penetration, and ARIMA error
correction.
5)Native load (energy) forecast derived
from retail load forecast.
6)Current forecast is the “Summer/Fall
Forecast” done in June.
1)Boot strap off medium term forecast.
2)Apply long-run load growth relationships to
develop simulation model for high/low
scenarios.
3)Include different scenarios for renewable
penetration with controls for price elasticity,
EV/PHEVs, and natural gas penetration.
Medium Term Long Term
9
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 226 of 1105
The Long-Term Relationship, 2021-2045
Load = Customers Χ Use Per Customer (UPC)
Load Growth ≈ Customer Growth + UPC Growth
Assumed to be same as population
growth for residential after 2025,
commercial growth will follow
residential, and slow decline in
industrial.
Assumed to be a function of
multiple factors including
renewable penetration, gas
penetration, and
EVs/PHEVs.
10
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 227 of 1105
Residential Customer Growth, 2020-2045
0.40%
0.50%
0.60%
0.70%
0.80%
0.90%
1.00%
1.10%
1.20%
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Annual Residential Customer Growth Rates
2021 IRP Residential Customer Growth 2020 IRP Residential Customer Growth
Medium Term Long Term
Average annual growth rate from
2021-2045 = 0.8%. Shape of
time-path mimics a combination
of IHS (ID) and OFM (WA)
population forecasts.
11
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 228 of 1105
Residential Solar Penetration, 2008-2019
0.00%
0.05%
0.10%
0.15%
0.20%
0.25%
0.30%
0.35%
305,000 310,000 315,000 320,000 325,000 330,000 335,000 340,000 345,000 350,000
Sh
a
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e

o
f

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s

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e
s
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l

Cu
s
t
o
m
e
r
s
Customers
Customer Penetration vs. Customers Since 2008
12
2014
2015
2016
2017
2018
2008
2019
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 229 of 1105
Residential Solar Penetration, 2021-2045
0
2,000
4,000
6,000
8,000
10,000
12,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
To
t
a
l

P
V

C
u
s
t
o
m
e
r
s
Projected Base-Line Residental Solar Customers
2021 IRP Base-Line Residential Solar Customers 2020 IRP Base-Line Residential Solar Customers13
Current penetration is 0.3% and typical
size is 7,800 watts. By 2045, penetration
will be near 2.6% of residential customers
and average size of installed systems will
be over 10,000 watts.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 230 of 1105
Residential EVs/PHEVs, 2021-2045
0
20,000
40,000
60,000
80,000
100,000
120,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
To
t
a
l

E
V
s
/
P
H
E
V
s
Projected Residental EVs/PHEVs
2020 IRP Projected EV/PHEV 2021 IRP Projected EV/PHEV
2020 ≈ 2,000
14
2045 ≈ 107,000
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 231 of 1105
Net Solar and EV/PHEV Impact, 2021-2045
-5
0
5
10
15
20
25
30
35
40
45
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Average Megawatt Impact of Solar and EV/PHEV
2021 IRP Solar aMW (Load Reduction)2021 IRP EV/PHEV aMW (Load Addition)2021 Net IRP Solar and EV/PHEV Impacts aMW15
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 232 of 1105
Native Load Forecast, 2021-2045
1,000
1,050
1,100
1,150
1,200
1,250
1,300
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Total Native Load Forecast, Average Megawatts
2021 IRP Base-Line Native Load 2020 IRP Base-Line Native Load
EV/PHEV “Bend”
IRP Avg. Annual
Growth
2020 IRP 0.3%
2021 IRP 0.3%
Medium Term Long Term
16
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 233 of 1105
Climate Change: A Trended 20-year Moving
Average (Preliminary!)
17
5,000
5,500
6,000
6,500
7,000
7,500
1965 1969 1973 1977 1981 1985 1989 1993 1997 2001 2005 2009 2013 2017 2021 2025 2029 2033 2037 2041 2045
HD
D
20-yr MA HDD
Annual 20-yr MA, Avista Trend Annual 20-yr MA, NWCC Trend Current 20-yr MA
0
100
200
300
400
500
600
700
800
1965 1969 1973 1977 1981 1985 1989 1993 1997 2001 2005 2009 2013 2017 2021 2025 2029 2033 2037 2041 2045
CD
D
20-yr MA CDD
Annual 20-yr MA, Avista Trend Annual 20-yr MA, NWCC Trend Current 20-yr MA
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 234 of 1105
Annual Native Load Forecast with Climate
Change, 2026-2045 (Preliminary!)
1,090
1,100
1,110
1,120
1,130
1,140
1,150
1,160
1,170
2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
2021 IRP Base-Line Native Load 2021 IRP Base-Line Native Load, Avista Trend 2021 IRP Base-Line Native Load, NWCC Trend18
IRP Avg. Annual Growth
2021 IRP, No Trend Base-Line 0.23%
2021 IRP, NWCC Trend 0.13%
2021 IRP, Avista Trend 0.21%
0.3% Lower than
Non-Trend Base-
Line
2% Lower than
Non-Trend Base-
Line
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 235 of 1105
Native Load Growth Forecast, 2021-2045
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
An
n
u
a
l

G
r
o
w
t
h
Native Load Growth
2021 IRP Base-Line Native Load Growth 2020 IRP Base-Line Native Load Growth19
EV/PHEV “Bend”
Load Recovery from
Recession
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 236 of 1105
Residential UPC Growth: 2021-2045
20
-1.5%
-1.0%
-0.5%
0.0%
0.5%
1.0%
1.5%
2.0%
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Base-Line Scenario: Residential UPC Growth Rate
EIA Refrence Case Use Per Household Growth 2021 IRP Residential Base-Line UPC Growth
Source Avg. Annual
Growth
2021 IRP -0.24%
EIA 0.03%
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 237 of 1105
Long-Run Load Forecast: Conservation
Adjustment
Grant D. Forsyth, Ph.D.
Chief Economist
[e-mail]
21
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 238 of 1105
Comparison of Native Load Forecasts, 2021-2045
900
1,000
1,100
1,200
1,300
1,400
1,500
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Average Megawatts Load Comparision with Conservation Adjustment
Base-Line Native Load Base-Line Native Load with Conservation Added Back
22
Source Avg. Annual
Growth
2021 IRP 0.3%
No Conservation 1.0%
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 239 of 1105
Peak Load Forecast
Grant D. Forsyth, Ph.D.
Chief Economist
[e-mail]
23
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 240 of 1105
The Basic Model
•Monthly time-series regression model that initially excludes certain industrial loads and
EVs (but those are added back in for the final forecast).
•Based on monthly peak MW loads since 2004. The peak is pulled from hourly load data for
each day for each month.
•Explanatory variables include HDD-CDD and monthly and day-of-week dummy variables.
The level of real U.S. GDP is the primary economic driver in the model—the higher GDP, the
higher peak loads. Model allows GDP impact to differ between winter and summer.
•The coefficients of the model are used to generate a distribution of peak loads by month
based on historical max/min temperatures since 1890, holding GDP constant. A starting
expected peak load is then calculated using the average peak load simulated for that
month going back to 1890. Model shows Avista is a winter peaking utility for the forecast
period; however, the summer peak is growing at a faster than the winter peak.
•For comparison in the 2021 IRP, peak load is also calculated by averaging simulated peak
loads over the last 30 years and 20 years.
•The model is also used to calculate the long-run growth rate of peak loads for summer and
winter using a forecast of GDP growth under the “ceteris paribus” assumption for weather
and other factors.
24
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 241 of 1105
Peak Forecasts for Winter and Summer, 2021-2045
1,100
1,200
1,300
1,400
1,500
1,600
1,700
1,800
1,900
2,000
19
9
7
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
20
1
3
20
1
5
20
1
7
20
1
9
20
2
1
20
2
3
20
2
5
20
2
7
20
2
9
20
3
1
20
3
3
20
3
5
20
3
7
20
3
9
20
4
1
20
4
3
20
4
5
Me
g
a
w
a
t
t
s
Winter Peak Summer Peak
Peak Avg. Growth 2021-45
Winter 0.37%
Summer 0.44%
25
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 242 of 1105
Load Forecasts for Winter Peak, 2011-2043
1,500
1,750
2,000
2,250
2,500
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Me
g
a
w
a
t
t
s
Winter Peak Forecast: Current and Past
2009 IRP 2011 IRP 2013 IRP 2015 IRP 2017 IRP 2020 IRP 2021 IRP
26
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 243 of 1105
Load Forecasts for Summer Peak, 2011-2045
1,500
1,750
2,000
2,250
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Me
g
a
w
a
t
t
s
Summer Peak Forecast: Current and Past
2009 IRP 2011 IRP 2013 IRP 2015 IRP 2017 IRP 2020 IRP 2021 IRP27
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 244 of 1105
Peak Forecasts for Winter and Summer 30-Year
Average Weather, 2021-2045
1,100
1,200
1,300
1,400
1,500
1,600
1,700
1,800
1,900
2,000
19
9
7
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
20
1
3
20
1
5
20
1
7
20
1
9
20
2
1
20
2
3
20
2
5
20
2
7
20
2
9
20
3
1
20
3
3
20
3
5
20
3
7
20
3
9
20
4
1
20
4
3
20
4
5
Me
g
a
w
a
t
t
s
Winter Peak Summer Peak28
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 245 of 1105
Peak Forecasts for Winter and Summer 20-Year
Average Weather, 2021-2045
1,100
1,200
1,300
1,400
1,500
1,600
1,700
1,800
1,900
2,000
19
9
7
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
20
1
3
20
1
5
20
1
7
20
1
9
20
2
1
20
2
3
20
2
5
20
2
7
20
2
9
20
3
1
20
3
3
20
3
5
20
3
7
20
3
9
20
4
1
20
4
3
20
4
5
Me
g
a
w
a
t
t
s
Winter Peak Summer Peak29
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 246 of 1105
Long-Run Customer Forecast: Natural
Gas
Grant D. Forsyth, Ph.D.
Chief Economist
[e-mail]
30
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 247 of 1105
Firm Customers (Meters) by State and Class, 2019
31
WA
47%
ID
24%
OR
29%
Firm Customers by State
Residential
90%
Commercial
10%
Industrial
0.1%
Firm Customers by Class
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 248 of 1105
System All Types of Industrial Customers, 1997-2020
200
210
220
230
240
250
260
270
280
290
300
0
5
10
15
20
25
30
35
19
9
7
19
9
8
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0

E
s
t
WA
-ID

F
i
r
m

I
n
d
u
s
t
r
i
a
l
OR

F
i
r
m

I
n
d
u
s
t
r
i
a
l
OR Firm Industrial WA-ID Firm Industrial32
291 31
216
24
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 249 of 1105
Customer Forecast Models
•Forecast models are structured around each schedule, in each class, by jurisdiction.
In the case of OR, this is done individually for each of Avista’s service islands.
•Time series transfer function models (models with regressions drivers and ARIMA
error terms).
•Simple time series smoothing models (for schedules with little customer variation).
•Same models used for the bi-annual revenue model forecast pushed out to 2045.
The forecasts for this IRP were generated from the “Summer/Fall 2020” forecast
completed in June.
•Customer forecasts are sent to Gas Supply for inclusion in the SENDOUT model.
•Example of transfer function model: WA sch. 101 residential customers…
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 250 of 1105
Transfer Function Model Example
34
𝐶𝐶𝑡𝑡,𝑦𝑦,𝑊𝑊𝑊𝑊101.𝑟𝑟=𝛼𝛼0 +𝜏𝜏𝑃𝑃𝑃𝑃𝑃𝑃𝑡𝑡,𝑦𝑦,𝑆𝑆𝑆𝑆𝑆𝑆+𝝎𝝎𝑺𝑺𝑺𝑺𝑺𝑺𝒕𝒕,𝒚𝒚+𝜔𝜔𝑂𝑂𝑂𝑂𝐷𝐷𝑂𝑂𝑂𝑂𝑡𝑡2015=1 +𝜔𝜔𝑂𝑂𝑂𝑂𝐷𝐷𝐹𝐹𝐹𝐹𝐹𝐹2016=1+𝜔𝜔𝑂𝑂𝑂𝑂𝐷𝐷𝑀𝑀𝑀𝑀𝑟𝑟2018=1 +𝜔𝜔𝑂𝑂𝑂𝑂𝐷𝐷𝑁𝑁𝑁𝑁𝑁𝑁2018=1 +𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝑡𝑡,𝑦𝑦12,1,0 0,0,0 12
Monthly
Customer
(Meter Count)
Monthly
Interpolated
Population for
Spokane MSA
Seasonal
Dummies
Outlier
Dummies
(Interventions)Error Correction
Component
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 251 of 1105
Getting to Population as a Driver, 2020-2025 & 2026-2045
Average GDP Growth
Forecasts:
•WSJ, FOMC,
Bloomberg, etc.
•Average forecasts
out 5 full calendar
years.
Non-farm Employment
Growth Model:
•Model links year y, y-1, and
y-2 GDP growth to year y
regional employment
growth.
•Forecast out 5 full calendar
years.
•Averaged with IHS
employment growth
forecasts.
Regional Population Growth Models:
•Model links regional, U.S., and CA
year y-1 employment growth to year y
county population growth.
•Forecast out 5 full calendar years for
Spokane, WA; Kootenai, ID; and
Jackson+Josephine, OR.
•Averaged with IHS growth forecasts.
•Growth rates used to generate
population forecasts for use in
regression models—important driver
for main residential and commercial
schedules.
EMPGDP
2020-2025 For Spokane, WA; Kootenai, ID, and
Jackson+Josephine, OR
OR Douglas, Klamath, and Union counties: IHS population growth forecasts for 2020-2045
Kootenai and Jackson: IHS population growth forecasts for 2026-2045
Spokane: OFM population growth forecasts for 2026-2045
Monlthly Interpolation assumes: PN = P0erN
Deviation in the most
recent forecast!
35
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 252 of 1105
WA-ID Region Firm Customers, 2021-2040 (2018 IRP)
220,000
240,000
260,000
280,000
300,000
320,000
340,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
WA-ID Base-line 2018 WA-ID Base-line 2021
IRP Avg.Annual Growth
2021-2040
2021 1.1%
2018 1.2%≈ +1,400
36
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 253 of 1105
OR Region Firm Customers, 2021-2040 (2018 IRP)
95,000
100,000
105,000
110,000
115,000
120,000
125,000
130,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
OR Base-line 2018 OR Base-line 2021
≈ -2,800
IRP Avg.Annual Growth
2021-2040
2021 0.8%
2018 0.9%
37
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 254 of 1105
Medford, OR Region Firm Customers, 2021-2040 (2018 IRP)
55,000
60,000
65,000
70,000
75,000
80,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
Medford Base-line 2018 Medford Base-line 2021
IRP Avg.Annual Growth
2021-2037
2021 0.9%
2018 0.9%≈ +310
38
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 255 of 1105
Roseburg, OR Region Firm Customers, 2021-2040 (2018 IRP)
14,000
15,000
16,000
17,000
18,000
19,000
20,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
Roseburg Base-line 2018 Roseburg Base-line 2021
≈ -1,900
IRP Avg.Annual Growth
2021-2040
2021 0.4%
2018 0.9%
39
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 256 of 1105
Klamath, OR Region Firm Customers, 2021-2040 (2018 IRP)
15,000
16,000
17,000
18,000
19,000
20,000
21,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
Klamath Base-line 2018 Klamath Base-line 2021
IRP Avg.Annual Growth
2021-2040
2021 0.7%
2018 1.0%
≈ -1,200
40
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 257 of 1105
La Grande, OR Region Firm Customers, 2021-2040 (2018
IRP)
7,400
7,600
7,800
8,000
8,200
8,400
8,600
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
La Grande Base-line 2018 La Grande Base-line 2021
IRP Avg.Annual Growth
2021-2040
2021 0.5%
2018 0.5%
≈ +30
41
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 258 of 1105
System Firm Customers, 2021-2040 (2018 IRP)
320,000
340,000
360,000
380,000
400,000
420,000
440,000
460,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
WA-ID-OR Base 2018 WA-ID-OR Base 2021
≈ -1,400
IRP Avg.Annual Growth
2021-2040
2021 1.0%
2018 1.1%
42
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 259 of 1105
WA-ID Region Firm Customer Range, 2021-2045
220,000
240,000
260,000
280,000
300,000
320,000
340,000
360,000
380,000
400,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
WAIDFIRMCUS Base WAIDFIRMCUS High WAIDFIRMCUS Low
Variable Low
Growth
Base
Growth
High
Growth
WA-ID Customers 0.7%1.1%1.5%
WA Population 0.4%0.7%1.0%
ID Population 0.8%1.4%2.0%
WA-ID Population 0.5%0.8%1.2%
43
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 260 of 1105
OR Region Firm Customer Range, 2021-2045
95,000
100,000
105,000
110,000
115,000
120,000
125,000
130,000
135,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
ORFIRMCUS Base ORFIRMCUS High ORFIRMCUS Low
Variable Low
Growth
Base
Growth
High
Growth
Customers 0.5%0.7%0.9%
Population 0.3%0.5%0.7%
44
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 261 of 1105
System Firm Customer Range, 2021-2045
300,000
350,000
400,000
450,000
500,000
550,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
SYSTEMCUS.syf Base SYSTEMCUS.syf High SYSTEMCUS.syf Low
Variable Low
Growth
Base
Growth
High
Growth
Customers 0.6%1.0%1.3%
Population 0.4%0.8%1.1%
45
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 262 of 1105
Summary of Growth Rates
System Base-Case High Low
1.0%1.4%0.7%
Commercial 0.5%0.8%0.1%
Industrial -0.8%2.2%-3.8%
Total 1.0%1.3%0.6%
WA Base-Case High Low
1.0%1.3%0.7%
Commercial 0.4%0.7%0.1%
Industrial -0.8%1.9%-3.6%
Total 1.0%1.3%0.7%
ID Base-Case High Low
1.4%2.0%0.8%
Commercial 0.4%1.0%-0.2%
Industrial -1.0%1.8%-3.4%
Total 1.3%1.9%0.7%
OR Base-Case High Low
0.7%0.9%0.5%
Commercial 0.6%0.8%0.4%
Industrial 0.0%4.5%-10.6%
Total 0.7%0.9%0.5%
46
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 263 of 1105
TAC 2.5 Meeting, September 18, 2020
Virtual Meeting Attendees: Nikita Bankoti, Washington UTC; Ben Cartwright; John
Chatburn, Idaho Energy Office; Corey Dahl, Washington Public Counsel; Ashton Davis;
Daniel Hua, NPPC; Kevin Keyt, IPUC; State of Idaho; Katie Pegan, OEMR; Steve
Johnson, Washington UTC; Charles Pegan; Dan Kirschner, NW Gas Association; Fred
Huette, NWEC; Gina Saraswati; Kate Griffith, Washington UTC; Joni Bosh, NWEC; L
Molander; Devin McGreal, Cascade Natural Gas; Michael Eldred, IPUC; Mike Morrison,
IPUC; Morgan Brummund, Idaho Energy Office; Greg Nothstein, Washington
Department of Commerce; Andrew Rector, Washington UTC; Richard Keller, IPUC; Ken
Ross, Fortis; Sudeshna Pal, Oregon CUB; Ted Light; Terrence Browne, Avista; Vlad
Gutman-Britten, Climate Solutions; Yao Yin, IPUC; Tom Pardee, Avista; Jody
Morehouse, Avista; Jaime Majure, Avista; Paul Kimmell, Avista; Theophania Labay,
Avista; John Lyons, Avista; Lori Hermanson, Avista; James Gall, Avista; Grant Forsyth,
Avista; Ryan Finesilver, Avista; Michael Brutocao, Avista; Mike Tatko, Avista; Amanda
Ghering, Avista; Clint Kalich, Avista; Shawn Bonfield, Avista; Marissa Warren, IPUC;
two Unavailable; and four Guests
Replies in italics after questions are made by the presenter in the following notes.
Economic Load and Customer Forecast (TAC 2.5)
Grant Forsyth: MSA stands for metropolitan service areas. Includes Spokane, Coeur
d’Alene, Lewiston/Clarkston, and Grants Pass in our service territory.
Grant Forsyth: [Slide 4]: Most or 2/3 is local government, and half or more of
government employment is for education.
Grant Forsyth: 2008 slowing job opportunities. Population growth means more job
opportunities. About 0.5% growth, 80-100% in-migration influencing load growth.
Steve Johnson: Now, generally speaking is there about a year lag between
employment growth and population about a year later? Yes, about that.
Steve Johnson: Population drives service territory growth. Do we know why 2014
surged above the nation? A little late in the process. Retirement demographic, jobs.
What does it correlate to GDP, higher or lower? Multiple reasons. Employment is a
primary driver. It has been an OK predictor in the past, but talk to people in real estate
and a robust economy comes with job growth. Low housing costs bring equity refugees
to the area after selling a house. OK, thanks.
Steve Johnson: Is there a separate forecast for layoffs that local governments might do
in the next 1.5 years and the rate of government job growth after that 1.5 year period?
No, it looks at total employment growth and the lagged by a year population growth.
Grant Forsyth: Employment is also part of the GDP growth forecast based on an
average of forecasts, at least over the medium term out to 2025. Big difference from
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 264 of 1105
June 2019 to June 2020 with a 6 percent decline in GDP, expect 4 percent growth next
year and then back down to 2 percent growth after 2022.
Andrew Rector: Do you run sensitivities on the growth rates? Yes, did run sensitivities
on this lately because of the COVID crisis with different types of recessions. The most
sensitive is the industrial side. Slowed employment growth slows customer growth for
two years after the recession, but clearly the most sensitive is industrial. Does that
answer your question? Yes, it does.
Grant Forsyth: Last year, I was asked to look at load if there was a recession every six
years. Found that we get to the same place, but more volatility builds more noise into
the model.
James Gall: There will be a high and a low load growth scenario. Not sure if we have it
later, but we can add it to the slide deck later.
Steve Johnson: There are various GDP underlying assumptions of how COVID plays
out. In regards to GDP estimates you used, do you know what the underlying
assumption was related to COVID and how that plays out?
Grant Forsyth: In some forecasts you can observe the underlying assumptions and
some you cannot. Some were predicting various things about COVID. Some were V
shaped, some square root, and others W shaped. But averaged together you get the
red line on Slide 7.
Steve Johnson: Does the company have an idea of how they think it’ll play out from
the scientists and economists?
Grant Forsyth: I’m allowed some discretion with that, but I tend to stick with a forecast
procedure that the Commissions are aware of and familiar with. I did not use a lot of
discretion using epidemiological sources. That is something I thought I’d never be asked
looking back on forecasts.
Steve Johnson: Is it the company’s forecast looking at the scientific community’s look
at a second wave? Do you think that is realistic? Does the Company agree a second
wave is sound scientific reasoning?
Grant Forsyth: When this was first going on people like me stopped forecasting early in
COVID. Even the Fed [U.S. Federal Reserve] stopped providing guidance. Started to
look at economists forecasting with epidemiologist input for one, two or three waves, but
it didn’t provide that much guidance that largely impact the forecast. The NEBR
[National Bureau of Economic Research] looked at how the Spanish Flu [in 1918].
Slide #9: Medium term of 2020 – 2025 is what we used in the revenue and earnings
model in June 2020. 20-year moving average of weather (2000-2019) that gets updated
every year.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 265 of 1105
Andrew Rector: When you say price do you mean price of electricity? Yes, own price
of electricity. Typically all-in annual prices – all revenues divided by usage for that
schedule)
Nikita Bankoti (Slide #9): Is GDP based on growth assumptions weighted a lot from
2020-2025?
Grant Forsyth: Good question. Typically what I’ll do is to not increase uncertainty in the
short run GDP for that period. I don’t necessarily increase the uncertainty from that
period.
Nikita Bankoti: I’m trying to understand if you assign an equal weight to GDP?
Grant Forsyth: Essentially a consensus as GDP filters through but no weighting.
Washington State weights their revenue model. I use a single GDP treated as a
consensus and drive that through the model. I don’t have any weightings like the state
does.
Nikita Bankoti: OK, that makes sense.
Mike Morrison: Multiplying customers by UPC isn’t difficult, mathematically. Why did
you use an approximation at all?
Grant Forsyth: I’m making sure everyone understands since not everyone does this
kind of work, so I start from the beginning and build up from there. There two
component parts you need to worry about to determine what’s driving load. Customer
growth and use per customer growth are the main things.
Andrew Rector: Can you say again? Overall the 0.8% is the same as the 2020
forecast, but shaped differently, is that what you’re saying?
Grant Forsyth: Yes. Taking it a step further, long term population growth is about 0.8%
on average. The U.S. is about 0.5% growth, so there is embedded in the forecast a
certain amount of in-migration for our service area.
Mike Morrison: Red line, increases and then precipitous drop in 2026 – what’s the drop
coming from?
Grant Forsyth: Long-term forecasts. That drop reflects what the third-party forecaster
are thinking will happen. Really the IHS forecast that can change from IRP to IRP based
on their own modeling processes. The OFM forecast is more stable because they don’t
update as often as IHS.
Steve Johnson (slide #12): Is this acceleration in Washington state and related to
incentives and programs?
Grant Forsyth: Washington probably dominates; if you look at customers who have
solar, it’s weighted to Washington. It is an assumption that we update as we get more
information. The cost has come down a lot on solar and that encourages more solar
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 266 of 1105
adoption. Also technological changes – roofs that look like shingles, but it’s actually
solar.
Steve Johnson: Are you modeling commercially available?
Grant Forsyth: Some are available and some are in testing, but when looking out over
time, assuming solar will accumulate at a rapid pace. It is an assumption. There is
another slide coming up that talks about this in more detail.
Yao Yin: Why isn’t residential solar considered from demand side versus supply side?
James Gall: Currently the customer controls that solar device and when it’s producing.
It belongs as a load component. In the event the utility offers incentives to change how
they operate, that’d be a demand-side resource, but it could translate into a supply side
resource.
Yao Yin: For other types of solar such as QF, do they belong to supply side? Yes.
Andrew Rector (Slide #12): What are your data sources for solar?
Grant Forsyth: Our own internal data from engineers that they collect. There is very
little non-solar net metering on our system anymore. The data includes customer
location and system size.
Nikita Bankoti (Slide #11): Again there is a lot of residential customer growth variation
in 2021-2023, variation in GDP forecast, is it a good idea for this variability to be
factored into the long-term forecast?
Grant Forsyth: I would need to think about this. Typically what happens with the
medium term forecast, it is currently set up to mesh with the medium term forecast for
the revenue model. The Company typically needs a medium term forecast to put into
the revenue model. One of the frustrations with forecasters is how to handle this current
COVID situation since it is atypical.
Steve Johnson: 10,000 watts in 2044. So that is a capacity factor of 15% on peak or
on average? On average, energy side rather than peak, approximately 10 aMW. It is on
a spreadsheet. I don’t need precision just a general sense. Are you modeling solar to
drop off before you get to your peak at 6 pm?
Grant Forsyth: It varies back and forth between 7 and 8 am to 5 to 6 pm where you
see the most peaks occur.
Steve Johnson: Is solar making a small impact on peak? Yes.
James Gall: On winter, solar is making virtually no impact on peak, but maybe some
peak shifting. In the summer, solar will reduce peak by about 60%. Subject to check, I
think it is about 14% capacity factor on rooftop solar (DC rating not AC rating)
Fred Heutte: What method are you using? Are you using a simple logistic regression
curve?
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 267 of 1105
Grant Forsyth: It assumes an exponential growth function out to 2045. At some time
we expect it to become logarithmic or some other type of term. It won’t go on forever at
this growth rate since we’re just getting started.
Fred Heutte: Are you taking into consideration technology and cost reductions?
Grant Forsyth: That’s why I’m assuming the size of growth due to technology
developments and cost reductions. Allowing the size to grow and as they develop more
solar, more ways to apply it.
Fred Heutte: I’m thinking about the experience curve. Can’t project current trends to the
longer term. Panel costs are not the majority of the costs now. Moved to telesales to
drop costs. May drive the market more going forward.
Grant Forsyth: Two big uncertainties to model the longer term – solar and EVs.
Fred Heutte: We are encouraging utilities to look at higher EV penetration scenarios.
Grant Forsyth: We do have EV charging shape built into our future forecast.
Fred Heutte: How do you do rate design so we don’t get a big hit?
Grant Forsyth: Where is policy going because that will shape a bunch of factors?
Currently difficult to get a sense of where that’s going.
James Gall: Commercial EVs?
Grant Forsyth: Residential EVs are highly correlated to growth in the commercial side.
They follow each other. Implicit assumption that as EV are accumulated on the
residential side, they’ll accumulate on the commercial side.
Andrew Rector: Does it take into account EVs yet like buses? No, it does not.
Yao Yin: Is there a similar assumption between residential and commercial solar?
Grant Forsyth: Yes, but solar is still weighted heavily to the residential side, but I’m
trying to maintain the correlation over time.
James Gall: Actually forecasting monthly, not hourly. We layer that into our models and
will talk at a future TAC about how we are doing that.
Slide #15: At what point EV load starts to negate of solar? The black dotted line. It
bends up about 2040. When it does occur, it has a significant effect on load behavior.
Mike Morrison: I don’t think aMW is a useful metric in planning what we care about. I’m
not sure of the relevance of aMW since capacity will occur over a couple of hours as
opposed to over 24 hours. It shows magnitude.
James Gall: This is only the first slide. Coincident peak slide is coming up. Energy
does matter – we look at peak and energy to meet both needs.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 268 of 1105
Yao Yin: For solar, we assume about 14% capacity factor, for EVs do we assume a
certain percentage for solar?
James Gall: Yes, it’s built into Grant’s model, but I can’t recall the exact factor. We look
at the capability of a charge and the kilowatt per hour. We don’t typically look at it that
way so I don’t have a factor right off.
Yao Yin: Do we assume certain hours EVs will get charged?
Grant Forsyth: Yes the profile tries to take that into effect.
Yao Yin: For the load forecast does this start monthly and peak hourly?
Grant Forsyth: Monthly and peak comes from Rendall’s load profiles. Starts with
hourly, converted to monthly. I may be misunderstanding your question.
Yao Yin: If we start with annual why do we convert to monthly?
Grant Forsyth: We are using monthly data to do peak load forecast so we have to
convert it to monthly.
James Gall: For the IRP, we do use the monthly peak and energy in order to get to
hourly. We look at winter/summer peak, annual energy.
Yao Yin: Another question regarding EVs, solar assumes about 14%, so do we have to
assume a capacity factor for charging?
James Gall: There is a battery draw built into the model. 3,000 to 5,000 kWh per year
depending on mileage. Great question.
Grant Forsyth: Assuming about 3,500 kWh per year from Rendall Farley’s EV analysis
submitted to the WUTC.
Yao Yin: Do you assume specific charging hours? Yes, it’s built into the load forecast
and taken into account.
Andrew Rector: Just for context, I have your EV plan in front of me with 3,153 kWh per
year. Sounds approximately right with what I entered.
Vlad Gutman-Britten: What period of time is the trend your green line is using? The
whole time period.
Mike Morrison: Is that a trend on individual years or 20-year moving average? Is that
legal with a time series?
Grant Forsyth: I don’t know if that’s legal. I could try that. If I recall correctly, time
series on a time series. It is heavily smoothed, but it’s not being done nefariously. Can
try it the other way certainly do it on the raw data.
Mike Morrison (Slide #17): So you got an increase of about 20% in cooling degree
days, so people are going to buy more ACs with up to over 700 cooling degree days?
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 269 of 1105
Grant Forsyth: This is my initial look, probably big implications for peak load; haven’t
done analysis for how I’d apply this to peak load. Additional adjustments will be needed.
Multiple effects – income increasing, AC costs declining – leads to more purchase of
ACs.
Fred Heutte: I had a little trouble on audio or dial in. On slide #18, double check of
additive of slightly higher cooling degree days and quite a bit lower heating degree
days. Yes, that is the net effect through the regression model. Agree with the approach
of a 20-year moving average. Need at least 10 years and more is better. We can’t go
back too far or we lose the signal. Inter-year variability is very large. This seems to be in
the right direction.
Grant Forsyth: Finally have analytically figured out how to shape that monthly. I
appreciate the comments from everybody.
Mike Morrison: As far as conservation, I believe you go those numbers from your
energy efficiency folks. We actually disagree with a lot of the numbers you got out of
your energy efficiency group. The IPUC has asked Avista’s conservation group to revisit
their energy savings because IPUC disagrees with their estimates – very much over
reporting.
Grant Forsyth: Fair enough. The information provided to me is what I have to work
with.
Mike Morrison: Not criticizing you, but the information is dubious. There is very much
over reporting in what energy efficiency has been doing.
James Gall: When we do capacity expansion modeling, we need an estimate of what
our load looks like with our conservation. DSM programs compete against other
resources. Based on what’s picked (conservation) we adjust the black line up or down
(slide 22).
Mike Morrison: Forecast based on average is that what we should be looking at.
Grant Forsyth: We do provide a band.
Mike Morrison: Are you really going to continue to be a winter peaking utility? I’m
concerned with how you’re doing your conservation programs (fuel switching).
Grant Forsyth: Yes, the conflict we face is the climate is changing, but the empirical
data shows that winter is still the peak period. Summer is moving up and we need to be
looking at an upper band.
James Gall: Grant is showing the average cold or hot day. In LOLP analysis, we
simulate those bands. We typically see a winder band in the winter and typically a
tighter band in the summer. This is used for loss of load based on probability of those
ranges; what is the probability of one of these peaks aligning with an outage as such.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 270 of 1105
Substantial amount of fuel-switching from electric to natural gas. That peak is now
removed. Both winter and summer are accounted for and optimized for.
Fred Heutte (slide 29): I have a comment about slide 25, but stay here. By eyeball it
looks summer, but still winter mathematically. LOLP makes most sense, most important
especially late summer – mid-July to mid-September.
Deborah Reynolds: As we’re thinking about how energy efficiency will be incorporated
into the load forecast, I’ve been thinking about taking the whole house efficiency and
how that will affect summer load. Weatherization affects both summer and winter. Be
thinking about how programs change over time. Ok, will do that.
Yao Yin: Winter and summer peak, have considered residential solar and EV
conservation?
Grant Forsyth: Solar is not as direct and is embedded only to the extent it’s in the
historical data. EV effects are more direct. Solar does not have the same impacts on
peak as EVs.
James Gall: We look at a peak credit to see how much it shaves peak. It was 2% in the
last plan.
Nikita Bankoti: Do you include gas transportation customers?
Grant Forsyth: Yes, I do a forecast for transportation but not for the IRP because we’re
looking at core load.
Tom Pardee (slide 32): Transportation customers are tasked with getting their own
transportation whereas we’re responsible for the firm gas customers.
Andrew Rector: Is it economic things driving IHS’s economic forecast in Roseburg?
Grant Forsyth: Yes, demographics. The only thing causing population growth is in-
migration or else it would be negative. I think they’re suggesting that in-migration is
restrained. Natural birth rate is zero or negative there and only growth is from in-
migration which they think will be lower than usual. It was revised down before the
shutdown.
Andrew Rector: Interesting context. Thanks.
Nikita Bankoti (slide 46): Negative industrial growth, is that from COVID?
Grant Forsyth: No that’s from a longer-term secular trend. This was in last IRP too. It
seems to be more of an acute problem in Washington than Idaho. Industrial companies
are exiting or relocating more heavily weighted towards Washington. Sneaking
suspicion that customers are going out of business or moving locations. Goes through
Actual May 2020 numbers but there could be some longer-term impacts from COVID
that may not appear for up to 24 months.
James Gall: What has the gas side seen from COVID?
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 271 of 1105
Grant Forsyth: I’d say gas data weathered better than east side out of heating.
Transportation customers being mostly industrial are a pretty good indicator of the
economy. Wood products firms, lumber, have done better with housing. Gas line
explosion caused some problem with switching from transport to firm schedules. The Air
Force Base and Idaho continue to be a surprise in terms of robust growth.
Deborah Reynolds: One last question. Have you looked at how robust transportation
conservation programs might impact gas transportation load and how much flexibility
there is in terms of the rate they pay?
Grant Forsyth: That’s a whopper. Many years ago, we had this conversation in
Oregon, at the time with the low gas costs, it didn’t make economic sense.
Tom Pardee: We can have Terrance speak about this on distribution if they are firm. If
on transportation, we can cut them. We’ll have an answer at the next TAC.
Deborah Reynolds: Legislation passed that you have to get ALL and that might include
transportation customers.
Shawn Bonfield: They don’t pay into the tariff.
Deborah Reynolds: I agree which is why I need you guys to do some work.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 272 of 1105
2021 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 3 Agenda
Tuesday, September 29, 2020
Virtual Meeting

Topic Time Staff
Introductions 9:00 Lyons

IRP Transmission Planning Studies 9:15 Spratt

Break 10:15

Distribution Planning within the IRP 10:30 Fisher

Lunch 11:30

Demand Response Potential Assessment 12:30 AEG Break 1:30 Conservation Potential Assessment 1:45 AEG
Electric Market Forecasts 2:45 Gall
Portfolio Scenarios 3:30 Lyons

Adjourn 4:00

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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 273 of 1105
2021 Electric IRP
TAC Introductions and IRP Process Updates
John Lyons, Ph.D.
Third Technical Advisory Committee Meeting
September 29, 2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 274 of 1105
Updated Meeting Guidelines
•Electric IRP team still working remotely, available by
email and phone for questions and comments
•Some processes are taking longer remotely
•Virtual IRP meetings until back in the office and able to
hold large group meetings
•Joint Avista IRP page for gas and electric:
https://www.myavista.com/about-us/integrated-resource-
planning
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 275 of 1105
Virtual TAC Meeting Reminders
•Please mute mics unless speaking or asking a question
•Use the Skype chat box to write questions or comments
or let us know you would like to say something
•Respect the pause
•Please try not to speak over the presenter or a speaker
who is voicing a question or thought
•Remember to state your name before speaking for the
note taker
•This is a public advisory meeting –presentations and
comments will be recorded and documented
3
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 276 of 1105
Integrated Resource Planning
•Required by Idaho and Washington* every other year
•Guides resource strategy over the next twenty + years
•Current and projected load & resource position
•Resource strategies under different future policies
–Resource choices
–Conservation measures and programs
–Transmission and distribution integration for electric
–Gas distribution planning
–Gas and electric market price forecasts
•Scenarios for uncertain future events and issues
•Key dates for modeling and IRP development are
available in the Work Plans
4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 277 of 1105
Technical Advisory Committee
•The public process piece of the IRP –input on what to study, how to
study, and review of assumptions and results
•Wide range of participants involved in all or parts of the process
–Ask questions
–Help with soliciting new members
•Open forum while balancing need to get through all of the topics
•Welcome requests for studies or different assumptions.
–Time or resources may limit the number or type of studies
–Earlier study requests allow us to be more accommodating
–August 1, 2020 was the electric study request deadline
•Planning teams are available by email or phone for questions or
comments between the TAC meetings
5
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 278 of 1105
2021 Electric IRP TAC Schedule
•TAC 1: Thursday, June 18, 2020
•TAC 2: Thursday, August 6, 2020 (Joint with Natural Gas TAC)
•TAC 2.5: Tuesday, August 18, 2020 Economic and Load Forecast
•TAC 3: Tuesday, September 29, 2020
•TAC 4: Tuesday, November 17, 2020
•TAC 5: Thursday, January 21, 2021
•Public Outreach Meeting: February 2021
•TAC agendas, presentations, meeting minutes and IRP files
available at:
https://myavista.com/about-us/integrated-resource-planning
6
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 279 of 1105
Process Updates
IRP data available on the web site:
•Avista Resource Emissions Summary
•Load Forecast
•CPA Measures
•Avista 2020 Electric CPA –Summary and IRP Inputs
•Home Electrification Conversions
•Named Populations
•Natural Gas Prices
•Social Cost of Carbon
7
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 280 of 1105
Today’s TAC Agenda
9:00 Introductions, Lyons
9:15 IRP Transmission Planning Studies, Spratt
10:15 Break
10:30 Distribution Planning within the IRP, Fisher
11:30 Lunch
12:30 Demand Response Potential Assessment, AEG
1:30 Break
1:45 Conservation Potential Assessment, AEG
2:45 Electric Market Forecasts, Gall
3:30 Portfolio Scenarios, Lyons
4:00 Adjourn
8
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 281 of 1105
Integrated Resource Plan (IRP)
Transmission Planning Studies
Dean Spratt, Transmission Planning
Third Technical Advisory Committee Meeting
September 29, 2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 282 of 1105
FERC Standards of Conduct
Non-public transmission information can not be
shared with Avista Merchant Function employees
There are Avista Merchant Function employees
attending today
We will not be sharing any non-public transmission
information. Avista’s OASIS is where this
information is made public
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 283 of 1105
Agenda
•Introduction to Avista System Planning
•Useful information about Transmission Planning
•Recent Avista projects
•Generation Interconnection Study Process
•Integrated Resource Plan (IRP) Requests
•Large Generation Interconnection Queue
3
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 284 of 1105
Introduction to Avista System Planning
Avista’s System Planning Group includes:
•Asset Performance and Management
•Distribution Planning
•Transmission Planning
–Focus on reliable electric service
•Federal, regional, and state compliance
•Regional system coordination
–Provide transmission service and system analysis
•Planned load growth and changing generation dispatch
•Interconnection of any type of generation or load
–We are ambivalent about type (must perform though)
4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 285 of 1105
Information About Transmission Planning
•We care about the Bulk Electric System (BES)
–Our 115 kV and 230 kV facilities (>100 kV)
•We identify issues where the Avista BES won’t
reliably deliver power to our customers
•Then put together plans to fix it
–“Corrective Action Plans”
–Mandated and described in NERC TPL-001-4
•We live in the world of NERC Mandatory
Standards
–Energy Policy Act of 2005
5
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 286 of 1105
TPL-001-4
•Describes outage conditions we must study
–P0: everything online and working
–P1: single facility outages, like a transformer
–P2, P4, P5 & P7: multiple facility outages
–P3 & P6: overlapping combination of two facilities
6
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 287 of 1105
TPL-001-4, cont.
•A couple of NERC directives for the above faults
–“The System shall remain stable”
•Cascading and uncontrolled islanding shall not occur
–“Applicable Facility Ratings shall not be exceeded”
•Equipment ratings, voltage, fault duty, etc
–“An objective of the planning process is to minimize
the likelihood and magnitude of Non-Consequential
Load Loss following planning events”
7
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 288 of 1105
Two Approaches to Reliability Issues
•Transmission Operations (TO) are guided by
significantly different standards than
Transmission Planning (TP).
•TO standards provide flexibility that TP
standards do not allow
–Operators can push system limits to SAVE the
interconnected system
•Shed load, overload equipment, etc –all short term
•The planned system should give them the tools to do this
•Standards continue to define this balance
8
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 289 of 1105
Standards are a Roadmap
Changes in equipment, analysis tools, experience, and expectations impact Avista’s
study process and results
9
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 290 of 1105
Recent Transmission Projects
10
BNT-OSS 115 kV
increase capacity
Westside 230/115 kV
increase capacity
SaddleMtn 230/115
kV new source
Neilson 115 kV new
switching station
115 kV underground
cable replacementSunset 115 kV rebuild
Moscow 230/115 kV increase capacity
CDA-PIN 115 kV increase capacity
BRX-CAB-SCK 115 kV
increase capacity
Adam Neilson20 MW Solar
Rattlesnake Flat144 MW Wind
Palouse105 MW Wind
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 291 of 1105
Non Wire Solutions are Evaluated
•We are documenting this with more clarity
•Non-wire options require robust wires to perform
–Avista is working on the transmission fundamentals
11
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 292 of 1105
Evaluated Batteries for T-1-1
•TPL-001-4 ~ T-1-1 for long lead equipment
–Double transformer outages
•Shawnee 230/115 kV outage followed by a:
–Concurrent outage of Moscow 230/115 kV
–Could we mitigate performance issues with storage?
•Yes…but…
–We would need a 125 MW battery
»Charge is 8 hours, discharge for 12 to 16 hours (outage is weeks to months)
–A third transformer is a better solution
»Robust performance and much less $$$$
12
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 293 of 1105
Generation Interconnection Study Process
Process for Generation Requests
•Two sources:
•External developers
•Enter via the OATT
•Internal IRP requests
•Feasibility Lite Study…then OATT
•AVA Merchant MUST follow the OATT just like external parties
•Typical process:
•Hold a scoping meeting to discuss particulars
•Outline a study plan
•Augment WECC approved cases for our studies
•Analyze the system against the standards
•Publish our findings and recommendations
13
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 294 of 1105
Interconnection Study Timeline
14
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 295 of 1105
Current Interconnection Queue
15
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 296 of 1105
Current Queue, continued
16
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 297 of 1105
2021 IRP TransmissionCost Estimates
Station Request (MW)POI Voltage Cost Estimate ($ million)
Kootenai County (GF)100 230 kV 4
Kootenai County (GF)200/300 230 kV 80-100
Rathdrum 25/50/100 115 kV <1
Rathdrum 200 115 kV 55
Rathdrum 50/100 230 kV <1
Rathdrum 200 230 kV 60
Benewah 100/200 230 kV <1
Tokio 50/100 115 <1, 20
Othello/Lind 50/100/200 115 kV Queue Issues
Lewiston/Clarkston 100/200 230 kV <1
Northeast 10 115 kV <1
Kettle Falls 12 115 kV <1
Kettle Falls 24/100/124 115 kV <20
Long Lake 68 115 kV 33
Monroe Street 80 115 kV 2
Post Falls 10 115 kV <1
Cabinet Gorge 110 230 kV <14
[1]Preliminary estimates are given as -25% to +75%17
Assume
anti-islanding
scheme, but
no RAS
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 298 of 1105
Monroe Street: 80 MW
18
Requires the Metro Rebuild
Project be completed
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 299 of 1105
Post Falls: 10 MW to 20 MW
19
Interconnection only
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 300 of 1105
Questions?
Avista OASIS link:
http://www.oasis.oati.com/avat/index.html
20
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 301 of 1105
Distribution Resource Planning
Damon Fisher, System Planning
Third Technical Advisory Committee Meeting
September 29, 2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 302 of 1105
Goals of Electric Distribution Planning
•Ensure electric distribution infrastructure to
serve customers now and in the future with a
focus on:
–Safety
–Reliability
–Capacity
–Efficiency
–Level of service
–Operational flexibility
–Corporate/Regulatory goals
–Affordability
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 303 of 1105
Distribution Resource Planning
•Washington House Bill 1126 (passed 2019)
–https://app.leg.wa.gov/RCW/default.aspx?cite=19.280.100
–10-Year Plan
–DER’s and Non-Wire Alternatives
–IRP Resource Needs
–Temporal and spatial planning
–Temporal and spatial value
–Probabilistic analysis (Pessimistic, Optimistic)
–Open Planning
3
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 304 of 1105
Primary Goal of Distribution Resource Plan
•Where possible, solve distribution grid
deficiencies using distributed energy resources
(DER) that also contribute to system resource
needs as identified in the Integrated Resource
Plan.
4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 305 of 1105
Can IRP resource needs and distribution
“fixes” be aligned? Certainly.
•Not without challenges.
–Temporal need
–Grid operation and flexibility
–Resource adequacy-a new distribution definition?
–System Protection
5
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 306 of 1105
Typical Distribution System Deficiencies
•Low Voltage
•Capacity (Substation/Feeder)
•Asset Condition
•Contingency Switching Limits
6
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 307 of 1105
What are DER’s? –Distribution’s Perspective
•Anything that can reduce demand or support
voltage
Real
Targeted Energy Efficiency
Targeted Demand Response
Apparent
Storage (Load shifting)
Generation (Load service)
7
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 308 of 1105
How Do DER’s Get Implemented?
•Three Paths-
1.Retail/Commercial Customer driven. Customers
install DER’s on their side of the meter for unknown
reasons.
2.The second way would be 3rd party grid connections
(utility scale). We have a few requests in the queue
and a 20MW installation in Lind Washington. These
can cause grid challenges.
3.The third way is utility-driven targeted DER’s to solve
grid issues on either side of the meter. Incentivized
#1 and #2 above.
8
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 309 of 1105
System Resources vs. Feeder Demand
9
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 310 of 1105
System Resources vs. Feeder Demand
10
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 311 of 1105
It Is All About Curves
•The ideal curve-
11
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 312 of 1105
It is all about curves
•A real curve (not ideal)-
12
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 313 of 1105
Can We Fix Curves with PV?
Community Solar – Summer
13
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 314 of 1105
Can We Fix Curves with PV?
Community Solar – Winter
14
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 315 of 1105
Can We Fix Curves with Just PV?
Community Solar –Cloudy Day, Battery
15
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 316 of 1105
Capacity Projects
53 Flint Road Station
Scope not complete.New distribution station located north of
Spokane along the Airway Heights -Sunset 115 kV Transmission Line.
Q3
2022
Budgeted
Not Scoped
98 Midway Station
Scope not complete.New distribution station located north of
Spokane along the Bell –Addy 115 kV Transmission Line.
Q1
2023
Budgeted
Not Scoped
80 Huetter Station Expansion
Scope not complete.Rebuild existing distribution station to
two 30MVA transformers, 6 feeders,
and looped through transmission with circuit breakers.
Q1 2025
Budgeted
Not Scoped
16
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 317 of 1105
Locations
17
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 318 of 1105
DRP Implementation Gaps
•Spatial Load Forecasting
•Spatial DER Forecasting
•System Performance Criteria
•DER Acquisition and Implementation Processes
•Engineering/Operational Expertise
18
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 319 of 1105
Interesting Distribution Efforts
•AMI data load disaggregation
•Hosting Capacity Maps
–Example Hosting Capacity map:
https://www.arcgis.com/apps/webappviewer/index.html?id=84de
299296d649808f5a149e16f2d87c
•Northwest Utility DER Technical Discussion
19
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 320 of 1105
Questions?
20
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 321 of 1105
Energy solutions. Delivered.
AVISTA DR POTENTIAL STUDY
Preliminary Results Slide Deck –Sep 28, 2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 322 of 1105
| 2Applied Energy Group · www.appliedenergygroup.com
Methodology
Program Characterization
Preliminary Impacts
Next Steps
AGENDA
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 323 of 1105
Methodology
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 324 of 1105
| 4Applied Energy Group · www.appliedenergygroup.com
Data Collection
•Align with EE Potential study
•Market Profiles
•Secondary Sources
•Industry or regional reports & previous studies
Characterize the Market
•Segmentation by Customer Class
•Residential and C&I (General Service, Large General Service and Extra Large General Service)
Develop list of DR Options
•DLC
•Third Party
•Storage
•Rates
•Ancillary Services
Characterize the Options
•Develop Program Assumptions
•Impacts, Participation, Technology, Costs, Incentives
Estimate Potential
•
•
•Realistic Achievable Potential
•Integrated case of cost-effective programs
APPROACH TO THE STUDY
Analysis Inputs Baseline Forecast Program List Potential Inputs Final Results
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 325 of 1105
| 5Applied Energy Group · www.appliedenergygroup.com
𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝐼𝐼𝑃𝑃𝐼𝐼𝑃𝑃𝐼𝐼𝐼𝐼𝑦𝑦𝑦𝑦𝑦𝑦𝑦𝑦,𝑝𝑝𝑦𝑦𝑝𝑝𝑝𝑝𝑦𝑦𝑦𝑦𝑝𝑝=𝑃𝑃𝑃𝑃𝑃𝑃𝐶𝐶𝐶𝐶𝐶𝐶𝐼𝐼𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝐼𝐼𝑃𝑃𝐼𝐼𝑃𝑃𝐼𝐼𝐼𝐼∗𝐸𝐸𝐸𝐸𝐸𝐸𝑃𝑃𝐸𝐸𝐸𝐸𝐸𝐸𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝐼𝐼𝐸𝐸𝐼𝐼𝐸𝐸𝐼𝐼𝑃𝑃𝑃𝑃𝐼𝐼𝐶𝐶∗𝑃𝑃𝑃𝑃𝑃𝑃𝐼𝐼𝐸𝐸𝐼𝐼𝐸𝐸𝐼𝐼𝑃𝑃𝐼𝐼𝐸𝐸𝑃𝑃𝑃𝑃 𝑅𝑅𝑃𝑃𝐼𝐼𝑃𝑃∗𝐸𝐸𝐸𝐸𝐶𝐶𝐸𝐸𝐼𝐼𝑃𝑃𝑃𝑃𝑃𝑃𝐼𝐼𝑆𝑆𝑃𝑃𝐼𝐼𝐶𝐶𝑃𝑃𝑃𝑃𝐼𝐼𝐸𝐸𝑃𝑃𝑃𝑃𝑅𝑅𝑃𝑃𝐼𝐼𝑃𝑃
where:
Year= Forecasted year between 2022 and 2045
CALCULATION OF IMPACT (MW)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 326 of 1105
Program Characterization
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 327 of 1105
| 7Applied Energy Group · www.appliedenergygroup.com
DR PROGRAM OPTIONS
Program Type Program Option Mechanism
Curtailable /
Controllable DR
DLC with two-way communicating or Smart T-stats Internet-enabled control of thermostat set points, can be coupled with any dynamic pricing
rate
DLC switch installed on customer’s Central AC
Modular communications interface for water heaters that will become the new technology
standard
DLC switch installed on customer’s Water Heater
Automated, fast-responding curtailment strategies with advanced telemetry capabilities
suitable for load balancing, frequency regulation, etc. Equipment considered for this option
includes:
Internet-enabled control of operational cycles of white goods appliances
DLC switch installed on customer’s equipment
Includes the following three measure options
Capacity Bidding Customers volunteer a specified amount of capacity during a predefined “economic event”
called by the utility in return for a financial incentive.
Emergency Curtailment Agreements Customers enact their customized, mandatory curtailment plan. May use stand-by
generation. Penalties apply for non-performance.
Demand Buyback Customers enact their customized, voluntary curtailment plan. May use stand-by generation.
No penalties for non-performance. Requires AMI technology.
Peak shifting of loads using stored electrochemical energy
Voluntary DR reductions in response to behavioral messaging. Example programs exist in CA
and other states. Requires AMI technology.
Peak shifting of primarily space cooling or heating loads using a thermal storage medium
such as water or ice
Higher rate for a particular block of hours that occurs every day. Requires either on/off peak
meters or AMI technology.
Much higher rate for a particular block of hours that occurs only on event days. Requires AMI
technology.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 328 of 1105
| 8Applied Energy Group · www.appliedenergygroup.com
Some of the options require AMI
•DLC Options-No AMI Metering Required
•Dynamic Rates-require AMI for billing
•Ancillary Options-require two way communicating controls
currently has 93% AMI saturation
•Assume 100% saturation by 2022
will start AMI rollout in 2022 and will take 18 months to fully deploy
•Assume 33% saturation in 2022 and 100% by 2024
AMI ASSUMPTIONS
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 329 of 1105
| 9Applied Energy Group · www.appliedenergygroup.com
Sources:
•DLC Central AC–NWPCC DLC Switch cooling assumption-5 yr ramp rate•DLC Smart Thermostats (Cooling)–NWPCC Smart Thermostat cooling assumption-5 yr ramp rate•DLC Smart Thermostats (Heating)–Agreed upon estimate with Avista. NWPC participation estimate was too high.•CTA –2045 WH -NWPCC Grid interactive WH assumptions.•DLC Water Heating –Best estimate based on industry experience –in line with other DLC programs•DLC Electric Vehicle Charging –NWPC Electric Resistance Grid-Ready Summer/Winter Participation-10 yr ramp rate•DLC Smart Appliances -2015 ISACA IT Risk Reward Barometer -US Consumer Results. October 2015. http://www.isaca.org/SiteCollectionDocuments/2015-risk-reward-survey/2015-isaca-risk-reward-consumer-summary-us_res_eng_1015.pdf
PARTICIPATION RATES
DLC PROGRAM OPTIONS
Program Option Residential General Service Large General
Service
Extra Large
General Service
DLC Central AC 10%10%
DLC Smart Thermostats -Cooling 20%20%
DLC Smart Thermostats -Heating 5%3%
CTA-2045 WH 50%50%
DLC Water Heating 15%5%
DLC Electric Vehicle Charging 25%
DLC Smart Appliances 5%5%
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 330 of 1105
| 10Applied Energy Group · www.appliedenergygroup.com
Sources:
•Third Party Contracts –Best estimate based on industry experience
•Thermal Energy Storage –Best estimate based on industry experience•Battery Energy Storage –Best estimate based on industry experience•Behavioral -PG&E rollout with six waves http://www.calmac.org/publications/DNVGL_PGE_HERs_2015_final_to_calmac.pdf•Time-of-Use Rates –Best estimate based on industry experience; Brattle Analysis and Estimate; Winter impacts ½ of summer impacts•Variable Peak Pricing Rates -OG&E 2017 Smart Hours Study•Real Time Pricing -Best estimate based on industry experience
PARTICIPATION RATES
RATES AND STORAGE
Program Option Residential General Service Large General
Service
Extra Large
General Service
Third Party Contracts 15%20%20%
Thermal Energy Storage 0.5%1.5%1.5%
Battery Energy Storage 0.5%0.5%0.5%0.5%
Behavioral 20%
Time-of-Use Opt-in 13%13%13%13%
Time-of-Use Opt-out 74%74%74%74%
Variable Peak Pricing Rates 25%25%25%25%
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 331 of 1105
| 11Applied Energy Group · www.appliedenergygroup.com
PEAK IMPACTS
DLC PROGRAMS
Season Program Option Residential General Service Large General
Service
Extra Large
General Service
Summer only DLC Central AC 0.5 kW 1.25 kW
Summer only DLC Smart Thermostats -Cooling 0.5 kW 1.25 kW
Winter only DLC Smart Thermostats -Heating 1.09 kW 1.35 kW
Annual CTA-2045 WH 0.5 kW 1.26 kW
Annual DLC Water Heating 0.5 kW 1.26 kW
Annual DLC Electric Vehicle Charging 0.5 kW
Annual DLC Smart Appliances 0.14 kW 0.14 kW
Sources:
•DLC Central AC and Smart Thermostats (Cooling)–NWPC DLC Switch cooling assumption was close to 1.0 kW reduced to adjust for Avista proposed cycling strategy, Thermostats equal to switch•DLC Smart Thermostats (Heating)–NWPC Smart thermostat heating assumption (east) •CTA-2045 Water Heating -NWPC Electric Resistance Grid-Ready Summer/Winter Impact, Gen Service is 2.52x that of res based on DLC Central AC Res to C&I ratio
•DLC Water Heating-NWPC Electric Resistance Switch Summer Impact, Gen Service is 2.52x that of res based on DLC Central AC Res to C&I ratio
•DLC Electric Vehicle Charging –Based on Avista Research
•DLC Smart Appliances -Ghatikar, Rish. Demand Response Automation in Appliance and Equipment. Lawrence Berkley National Laboratory, 2015. Web. http://docketpublic.energy.ca.gov/PublicDocuments/15-IEPR-05/TN205072_20150618T110004_Demand_Response_Automation_in_Appliances_and_Equipment.pptx
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 332 of 1105
| 12Applied Energy Group · www.appliedenergygroup.com
PEAK IMPACTS
RATES AND OTHER OPTIONS
Season Program Option Residential General Service Large General Service Extra Large General Service
Annual Third Party Contracts 10%21%21%
Annual Thermal Energy Storage 1.7 kW 8.4 kW 8.4 kW
Annual Battery Energy Storage 2 kW 2 kW 15 kW 15 kW
Annual Behavioral 2%
Annual Time-of-Use Rate Opt-in 5.7%0.2%2.6%3.1%
Annual Time-of-Use Rate Opt-out 3.4%0.2%2.6%3.1%
Annual Variable Peak Pricing Rates 10%4%4%4%
Sources:
•Third Party Contracts - Weighted average impacts from report: Impact Estimates from Aggregator Programs in California (Source: 2019 Statewide Load Impact Evaluation of California Aggregator Demand Response Programs)
•Thermal Energy Storage -Ice Bear Tech Specifications, https://www.ice-energy.com/wp-content/uploads/2016/03/ICE-BEAR-30-Product-Sheet.pdf
•Battery Energy Storage –Typical Battery size per segment
•Behavioral -Opower documentation for BDR with Consumers and DTE
•Time-of-Use Rates –Brattle Analysis and Estimate -PacifiCorp 2019 opt-in and opt-out scenarios. Summer Impacts Shown (Winter impacts ½ summer)
•Variable Peak Pricing Rates -OG&E 2018 Smart Hours Study, Summer Impacts Shown (Winter impacts ¾ summer)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 333 of 1105
| 13Applied Energy Group · www.appliedenergygroup.com
AVERAGE EVENT DURATION FOR
DLC OPTIONS
Option Annual Event Hours Average Duration per Event Max Event Duration
Central AC 50 3 hrs 6 hrs
Smart Thermostats -Cooling 36 3 hrs 6 hrs
Smart Thermostats -Heating 36 3 hrs 6 hrs
Water Heating 100 3 hrs 6 hrs
Electric Vehicle Charging 528 6 hrs 8 hrs
Smart Appliances 528 6 hrs 8 hrs
Third Party Contracts 30 4 hrs 8 hrs
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 334 of 1105
Technical Achievable Potential
DLC Options
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 335 of 1105
| 15Applied Energy Group · www.appliedenergygroup.com
TECHNICAL ACHIEVABLE POTENTIAL
WINTER -DLC OPTIONS
Sector Option 2022 2025 2035 2045
Residential DLC Central AC ----
CTA-2045 WH 0.0 1.3 21.1 38.5
DLC Water Heating 0.5 4.3 4.7 4.6
DLC Smart Appliances 0.3 2.4 3.0 3.3
DLC Smart Thermostats -Cooling ----
DLC Smart Thermostats -Heating 0.8 7.8 9.5 10.5
DLC Electric Vehicle Charging -0.3 5.6 30.2
DLC Central AC ----
CTA-2045 WH 0.0 0.3 5.2 10.4
DLC Water Heating 0.1 0.6 0.8 0.9
DLC Smart Appliances 0.0 0.3 0.3 0.4
DLC Smart Thermostats -Cooling ----
DLC Smart Thermostats -Heating 0.0 0.2 0.3 0.3
Third Party Contracts 4.6 21.9 21.8 21.9
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 336 of 1105
| 16Applied Energy Group · www.appliedenergygroup.com
TECHNICAL ACHIEVABLE POTENTIAL
SUMMER -DLC OPTIONS
Sector Option 2022 2025 2035 2045
Residential DLC Central AC 0.6 6.8 14.5 23.7
CTA-2045 WH 0.0 1.3 21.1 38.5
DLC Water Heating 0.5 4.3 4.7 4.6
DLC Smart Appliances 0.3 2.4 3.0 3.3
DLC Smart Thermostats -Cooling 1.2 13.5 29.1 47.4
DLC Smart Thermostats -Heating ----
DLC Electric Vehicle Charging -0.3 5.6 30.2
DLC Central AC 0.2 1.9 4.1 6.8
CTA-2045 WH 0.0 0.3 5.2 10.4
DLC Water Heating 0.1 0.6 0.8 0.9
DLC Smart Appliances 0.0 0.3 0.3 0.4
DLC Smart Thermostats -Cooling 0.3 3.8 8.3 13.5
DLC Smart Thermostats -Heating ----
Third Party Contracts 4.5 21.4 21.3 21.4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 337 of 1105
Technical Achievable Potential
Rates and Other Options
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 338 of 1105
| 18Applied Energy Group · www.appliedenergygroup.com
TECHNICAL ACHIEVABLE POTENTIAL
WINTER -RATES AND OTHER OPTIONS
Sector Option 2022 2025 2035 2045
Residential Time-of-Use Opt-in 0.4 5.0 5.9 6.2
Time-of-Use Opt-out 19.6 19.4 20.0 21.1
Variable Peak Pricing Rates 1.4 16.8 19.7 20.8
Battery Energy Storage 0.1 0.6 4.3 4.8
Behavioral 0.6 3.0 3.1 3.3
Time-of-Use Opt-in 0.1 1.4 1.6 1.5
Time-of-Use Opt-out 10.4 9.2 8.9 8.8
Variable Peak Pricing Rates 0.5 5.3 6.0 6.1
Thermal Energy Storage ----
Battery Energy Storage 0.0 0.1 0.7 0.8
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 339 of 1105
| 19Applied Energy Group · www.appliedenergygroup.com
TECHNICAL ACHIEVABLE POTENTIAL
SUMMER -RATES AND OTHER OPTIONS
Sector Option 2022 2025 2035 2045
Residential Time-of-Use Opt-in 0.5 5.4 6.3 6.6
Time-of-Use Opt-out 21.1 20.7 21.4 22.5
Variable Peak Pricing Rates 1.5 17.9 21.0 22.2
Battery Energy Storage 0.1 0.6 4.3 4.8
Behavioral 0.6 3.2 3.4 3.5
Time-of-Use Opt-in 0.1 1.4 1.5 1.5
Time-of-Use Opt-out 10.1 8.9 8.6 8.5
Variable Peak Pricing Rates 0.5 5.2 5.9 6.0
Thermal Energy Storage 0.1 0.7 0.8 0.8
Battery Energy Storage 0.0 0.1 0.7 0.8
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 340 of 1105
Ancillary Services
By Option
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 341 of 1105
| 21Applied Energy Group · www.appliedenergygroup.com
Participation Assumptions
•Full for Battery/EV/WH
•Half for Heating/Cooling
•Third Party based on saturations of EMS systems for
PAC C&I
•Full for Battery/WH
•75% for Third Party
•Half for Heating/Cooling/EV
ANCILLARY SERVICE ASSUMPTIONS
Ancillary Option
Battery Energy Storage
Electric Vehicle Charging
DLC Smart Thermostats- Cooling
DLC Smart Thermostats- Heating
DLC Water Heaters
CTA-2045 Water Heaters
Third Party Contracts
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 342 of 1105
| 22Applied Energy Group · www.appliedenergygroup.com
ANCILLARY SERVICES
TECHNICAL ACHIEVABLE POTENTIAL
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 343 of 1105
DR Event Shapes
Load Shifting Assumptions
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 344 of 1105
| 24Applied Energy Group · www.appliedenergygroup.com
In order to incorporate the impacts into the IRP we need to understand how an even effects overall consumption
Depending on the program type, calling an event can have different effects
•Save energy (0% shift)
•Shift energy (100% shift)
•Partial shift
The next slide will show specific examples of each
SHIFT OR SAVE
Graph shows typical event shape
for a Residential Variable Peak
Pricing program
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 345 of 1105
| 25Applied Energy Group · www.appliedenergygroup.com
EVENT LOAD SHAPES
Program
State
Season Winter Summer Winter Summer Winter Summer Winter Summer Winter Summer Winter Summer Winter Summer Winter Summer
Pre-Event Shift Ratio 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 35% 35% 35% 35%
Post-Event Shift Ratio 65% 65% 65% 65% 100% 100% 100% 100% 0% 0% 0% 0% 65% 65% 65% 65%
Impact at Peak (kW)0.50 0.50 0.50 0.50 0.50 0.50 0.50 0.50
Peak Impact Percentage 24.9% 23.1% 26.7% 25.5% 24.9% 23.1% 26.7% 25.5% 2.9% 5.7% 2.9% 5.7% 7.5% 10.0% 7.5% 10.0%
Hour Ending
1 - - - - - - - - - - - - - - - -
14 - - - - - - - - - - - - - - - -
15 - - - - - - - - - - - - (0.08) (0.11) (0.07) (0.10)
16 - - - - - - - - - - - - (0.08) (0.11) (0.07) (0.10)
17 0.43 0.46 0.46 0.46 0.46 0.46 0.46 0.46 0.05 0.11 0.05 0.10 0.14 0.20 0.13 0.18
18 0.46 0.49 0.50 0.49 0.50 0.49 0.50 0.49 0.06 0.12 0.05 0.11 0.15 0.21 0.14 0.19
19 0.46 0.50 0.50 0.50 0.50 0.50 0.50 0.50 0.06 0.12 0.05 0.11 0.15 0.22 0.14 0.20
20 (0.29) (0.31) (0.32) (0.31) (0.37) (0.36) (0.37) (0.36) - - - - (0.10) (0.14) (0.09) (0.12)
21 (0.29) (0.31) (0.32) (0.31) (0.37) (0.36) (0.37) (0.36) - - - - (0.10) (0.14) (0.09) (0.12)
22 (0.29) (0.31) (0.32) (0.31) (0.37) (0.36) (0.37) (0.36) - - - - (0.10) (0.14) (0.09) (0.12)
23 - - - - (0.37) (0.36) (0.37) (0.36) - - - - - - - -
24 - - - - - - - - - - - - - - - -
Full Shift spread out before/after event
Time-Of-Use Opt-In
WA ID
Partial Shift Full Shift Full Save
Variable Peak Pricing
WA ID
DLC Central AC
WA ID
CTA-2045 Water Heating
WA ID
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 346 of 1105
Next Steps
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 347 of 1105
| 27Applied Energy Group · www.appliedenergygroup.com
Finalize Technical Achievable Potential
Characterize Program Costs
Estimate Achievable Potential
•Integrated case
•Calculate levelized costs
Finalize Results
NEXT STEPS
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 348 of 1105
Kelly Marrin, Managing Director
[e-mail]
Tommy Williams, Lead Analyst
[e-mail]
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 349 of 1105
Energy solutions. Delivered.
2020 CONSERVATION POTENTIAL
ASSESSMENT –UPDATE
Prepared for the Avista Technical Advisory Commitee
September 29, 2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 350 of 1105
| 2Applied Energy Group · www.appliedenergygroup.com
AGENDA
Topics
•AEG Introduction
•AEG’s CPA Methodology
•Electric CPA Summary
•DR Analysis Summary
•Natural Gas CPA Summary
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 351 of 1105
| 3Applied Energy Group · www.appliedenergygroup.com
ABOUT AEG
Planning
Baseline studies
Market assessment studies
Program design & action plans
End-use forecasting
EM&V
EE portfolio & targeted programs
Demand response programs & dynamic pricing
Pilot design & experimental design
Behavioral programs
Implementation &
Technical Services
Engineering review, due-diligence, QA/QC
M&V, modeling & simulation, onsite
assessments
Technology R&D and data tools (DEEM)
Program admin,
marketing, implementation, application processing
Market Research
Program / service pricing optimization
Process evaluations
Market assessment / saturation surveys
Customer satisfaction / customer engagement
Market segmentation
VISION DSMTM Platform
Full DSM lifecycle tracking & reporting
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 352 of 1105
| 4Applied Energy Group · www.appliedenergygroup.com
Including Potential Studies and End-Use Forecasting
AEG has conducted more than 60 planning studies for more than 40 utilities / organizations in the past five years.
AEG has a team of 11 experienced Planning staff plus support from AEG’s Technical Services and Program Evaluation groups
AEG EXPERIENCE IN PLANNING
Northwest & Mountain:Avista*BPA*Cascade Natural GasChelan PUDCheyenne LFPColorado Electric*Cowlitz PUD*
Inland P&L*Oregon Trail ECPacifiCorp*PNGCPGE*Seattle City Light*Tacoma Power*
HECOLADWPNV Energy*Public Service New Mexico* State of HawaiiState of New MexicoXcel/SPS
Ameren Illinois*Ameren Missouri*Citizens EnergyEmpire District ElectricIndianapolis P&L*Indiana & Michigan Utilities
Kansas City Power & Light MERCNIPSCO*Omaha Public Power DistrictState of MichiganVectren Energy*
Central Hudson G&E*Con Edison of NY*New Jersey BPUPECO EnergyPSEG Long IslandState of Maryland (BG&E, DelMarva, PEPCO, Potomac Edison, SMECO)
Midcontinent ISO*EEI/IEE*EPRI FERC
OG&EKentucky PowerSouthern Company (APC,GPC, Gulf Power, MPC)TVA
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 353 of 1105
AEG CPA Methodology
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 354 of 1105
| 6Applied Energy Group · www.appliedenergygroup.com
The Avista Conservation Potential Assessment (CPA) supports the Company’s regulatory filing and other demand-side management (DSM)
planning efforts and initiatives.
The two primary research objectives for the 2020 CPA are:
•Program Planning:insights into the market for electric and natural gas energy
efficiency (EE) measures and electric demand response (DR) measures in Avista’s Washington and Idaho service territories
For example, CPAs provide insight into changes to existing program measures as well as new measures to consider
•IRP: long-term forecast of future EE and DR potential for use in the IRP
Technical Achievable Potential (TAP) for electricity
Economic Achievable Potential (EAP) for natural gas
AEG utilizes its comprehensive LoadMAP analytical models that are
customized to Avista’s service territory.
CPA OBJECTIVES
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 355 of 1105
| 7Applied Energy Group · www.appliedenergygroup.com
Overview –Electric and GasOVERVIEW OF AEG’S APPROACH
Market Characterization
•Avista control totals•Customer account data
•Secondary data•Avista market research
Identify Demand-Side Resources
•EE technologies
•EE measures•Emerging measures and technologies
Baseline Projection
•Avista Load Forecast•Customer growth
•Standards and building codes
•Efficiency options•Purchase Shares
Potential Estimation
•Technical•Technical Achievable•Economic Screen (TRC and UCT) are handled by Avista’s IRP
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 356 of 1105
| 8Applied Energy Group · www.appliedenergygroup.com
Prioritization of Avista Data
Data from Avista was prioritized when available, followed by regional data, and finally well-vetted national data.
•2013 Residential GenPop Survey
•Forecast data and load research
•Recent-year accomplishments and plans
•NEEA studies (RBSA 2016, CBSA 2019, IFSA)
•RTF and Power Council methodologies, ramp rates, and measure assumptions
•U.S. DOE’s Annual Energy Outlook
•U.S. DOE’s projections on solid state lighting technology improvements
•Technical Reference Manuals and California DEER
•AEG Research
KEY SOURCES OF DATA
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 357 of 1105
| 9Applied Energy Group · www.appliedenergygroup.com
Overview
“How much energy would customers use in the future if Avista stopped running programs now and in the absence of naturally occurring efficiency?”
•The baseline projection answers this question
The baseline projection is an independent end-use forecast of electric or natural gas consumption at the same level of detail as the market profile
BASELINE PROJECTION
Includes
•To the extent possible, the same forecast drivers used in
the official load forecast, particularly customer growth,
natural gas prices, normal weather, income growth, etc.
•Trends in appliance saturations, including distinctions for new construction.
•Efficiency options available for each technology , with share of purchases reflecting codes and standards (current and finalized future standards)
•Expected impact of appliance standards that are “on the books”
•Expected impact of building codes, as reflected in market profiles for new construction
•Market baselines when present in regional planning assumptions
Excludes
•Expected impact of naturally occurring efficiency (except
market baselines)
•Exception:RTF workbooks have a market baseline for
lighting, which AEG’s models also use.
•Impacts of current and future demand-side management programs
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 358 of 1105
Electric CPA
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 359 of 1105
| 11Applied Energy Group · www.appliedenergygroup.com
AVISTA 2020 ELECTRIC CPA
CPA Methodology Overview
•Levels of Potential
•Economic Evaluation and IRP Integration
•Retained enhancements from 2018 Action Plan
Summary of EE Results
•Summary of Potential
High level results
Top measures
Potential by cost bundles
•Comparison to previous CPA
Summary of DR Results
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 360 of 1105
| 12Applied Energy Group · www.appliedenergygroup.com
•Focus of the study is to explore a wide range of options for reducing annual energy use
•This study develops two sets of estimates:
•Technical potential (TP): everyone chooses the mostefficient option possible when equipment fails
•This may include emerging or very expensive
ultra-high efficiency technologies
•Technical Achievable Potential (TAP) is a subset of TP that accounts for customer preference and likelihood to adopt through utility-and non-utility driven mechanisms
•To better emulate likely programs, Technical Achievable
Potential calculates savings from efficient options more likely
to be selected by the IRP
•In addition to these estimates, the study produces cost data for the TRC and UCT tests that can be used by Avista’s IRP process to select energy efficiency measures in competition with other resources
TWO LEVELS OF SAVINGS ESTIMATES
Technical
Technical
Achievable
Power Council Methodology
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 361 of 1105
| 13Applied Energy Group · www.appliedenergygroup.com
Two Cost-Effectiveness TestsECONOMIC METRICS
AEG provided a levelized net cost of energy ($/kWh) for each measure
within the achievable potential
within Avista’s Washington and
Idaho territories from two perspectives.
•Utility Cost Test (UCT): Assesses cost-
effectiveness from a utility or program administrator’s perspective.
•Total Resource Cost Test (TRC):
Assesses cost-effectiveness from the utility’s and participant’s perspectives. Includes non-energy
impacts if they can be quantified and monetized.
Component UCT TRC
Avoided Energy Benefit Benefit
Non-Energy Benefits*Benefit
Incremental Cost Cost
Incentive Cost
Administrative Cost Cost Cost
Non-Energy Costs* (e.g. O&M)Cost
*Council methodology includes monetized
impacts on other fuels within these categories
Both values are provided to Avista for all
measure level potential, so that the IRP can use the appropriate evaluation for each state: TRC for WA and UCT for ID.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 362 of 1105
| 14Applied Energy Group · www.appliedenergygroup.com
AEG has preserved the enhancements to the CPA process that were included in the previous CPA:
•Any measures screened out in advance of technical potential are documented in the measure list along with the reason. As before, very few measures were
excluded in this step
Measures that were excluded were generally either emerging measures with
insufficient data to characterize properly, or highly custom measures that are instead modeled within broader retrocommissioning or strategic energy management
programs.
•Full Technical Achievable potential is provided to the IRP along with TRC and
UCT costs for each measure
•The Measure Assumptions appendix is again available, containing UES data
and other key assumptions and their sources
•Demand Response potential includes analysis of both Summer and Winter possible programs
ENHANCEMENTS RETAINED FROM 2018
CPA
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 363 of 1105
| 15Applied Energy Group · www.appliedenergygroup.com
Achievability
All potential “ramps up” over time –all ramp rates are based
on those found within the NWPCC’s 2021 Power Plan
•Max Achievability
•NWPCC 2021 Plan allows some measures
max achievability to reach up to 100% of technical potential
•7th Power Plan and prior CPA had a max
achievability of 85%
•AEG has aligned assumptions with the 2021
Plan and measures such as lighting reach greater than 85%
•Please note Power Council’s ramp rates include potential
realized from outside of utility DSM programs, including regional initiatives and market transformation
POTENTIAL ESTIMATES
Measures examples over 85% Achievability:
•All Lighting
•Washers/Dryers
•Dishwashers
•Refrigerators/Freezers
•Circulation Pumps
•Thermostats
•C&I Fans
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 364 of 1105
| 16Applied Energy Group · www.appliedenergygroup.com
Potential Summary –WA & ID All SectorsENERGY EFFICIENCY POTENTIAL
Projections indicate that energy savings of ~1.0% of baseline
consumption per year are
Technically Achievable.
•190 GWh (22 aMW) in biennium period (2022-2023)
•1,317 GWh (150 aMW) by 2031
•This level of savings offsets future load growth
-
2,000.0
4,000.0
6,000.0
8,000.0
10,000.0
12,000.0
GWh
Annual Energy Projections
Baseline Projection
Achievable Technical Potential
Technical Potential
0
50
100
150
200
250
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Annual Incremental Potential (GWh)
Achievable Technical Potential Technical Potential
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 365 of 1105
| 17Applied Energy Group · www.appliedenergygroup.com
EE POTENTIAL, CONTINUEDPotential Summary –WA & ID, All Sectors
Summary of Energy Savings (GWh),
Selected Years 2022 2023 2025 2031 2041 2045
Reference Baseline
Cumulative Savings (GWh)
Technical Achievable Potential
Technical Potential
Energy Savings (% of Baseline)
Technical Achievable Potential
Technical Potential
Incremental Savings (GWh)
Technical Achievable Potential
Technical Potential
0
500
1,000
1,500
2,000
2,500
2022 2025 2028 2031 2034 2037 2040 2043
Cumulative ATP Savings (GWh) by Sector
Residential Commercial Industrial
0%
5%
10%
15%
20%
25%
30%
35%
2022 2023 2025 2031 2041 2045
% of
Baseline
Cumulative Electric Savings, selected years
Technical Achievable Potential Technical Potential
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 366 of 1105
| 18Applied Energy Group · www.appliedenergygroup.com
ATP Peak Savings Summary –WA & ID, All SectorsEE POTENTIAL -CONTINUED
EE Peak Savings (MW),
Selected Years 2022 2023 2025 2031 2041 2045
Reference Baseline
Summer Peak MW
Winter Peak MW
Cumulative Savings (MW)
Summer Peak
Winter Peak
Cumulative Savings (% of Baseline)
Summer Peak
Winter Peak
Incremental Savings (MW)
Summer Peak
Winter Peak
-
50
100
150
200
250
300
350
400
2022 2025 2028 2031 2034 2037 2040 2043
ATP Summer Peak Savings (MW)
Residential Commercial Industrial
-
50
100
150
200
250
300
350
400
2022 2025 2028 2031 2034 2037 2040 2043
ATP Winter Peak Savings (MW)
Residential Commercial Industrial
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 367 of 1105
| 19Applied Energy Group · www.appliedenergygroup.com
Achievable Technical Potential –WA & IDEE POTENTIAL BY SECTOR
2022 2023 2024 2031 2041
Baseline projection (GWh)
Residential 3,774 3,785 3,796 3,953 4,489
Commercial 3,223 3,234 3,248 3,427 3,924
Industrial 845 843 839 812 780
Total Consumption (GWh)7,842 7,863 7,883 8,192 9,193
ATP Cumulative Savings (GWh)
Residential 32 72 120 623 1,004
Commercial 46 97 152 583 819
Industrial 10 21 33 110 151
Total Savings (GWh)88 190 304 1,317 1,974
ATP Cumulative Savings (aMW)
Residential 4 8 14 71 115
Commercial 5 11 17 67 94
Industrial 1 2 4 13 17
Total Savings (aMW)10 22 35 150 225
ATP Cumulative Savings as a % of Baseline
Residential 0.8%1.9%3.1%15.8%22.4%
Commercial 1.4%3.0%4.7%17.0%20.9%
Industrial 1.2%2.5%3.9%13.6%19.3%
Total Savings (% of Baseline)1.1%2.4%3.9%16.1%21.5%
0.0%
5.0%
10.0%
15.0%
20.0%
25.0%
2022 2023 2024 2031 2041
ATP Savings by Sector (% of Baseline)
Residential Commercial Industrial
0
500
1,000
1,500
2,000
2,500
2022 2025 2028 2031 2034 2037 2040 2043
Cumulative ATP Savings (GWh) by Sector
Residential Commercial Industrial
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 368 of 1105
| 20Applied Energy Group · www.appliedenergygroup.com
Cumulative Potential Summary –WA & ID All SectorsEE POTENTIAL -TOP MEASURES
Technical Achievable Potential, Ranked by Savings in 2031 (MWh)
Rank Measure / Technology
2023 Achievable
(MWh)
% of Total
2031 Achievable
(MWh)
% of Total
TRC
Levelized
$/kWh
UCT
Levelized
$/kWh
1 -Linear Lighting 9,139 62,302
2 -Retrocommissioning 9,318 59,994
3 -Water Heater <= 55 Gal 2,647 55,156
4 -Strategic Energy Management 7,047 44,581
5 -Ductless Mini Split Heat Pump (Zonal)6,599 42,085
6 -ENERGY STAR -Connected Thermostat 5,890 40,216
7 -Windows -High Efficiency/ENERGY STAR 5,808 35,780
8 -Ductless Mini Split Heat Pump with Optimized 1,485 33,420
9 -Home Energy Management System (HEMS)4,975 30,271
10 -Windows -Cellular Shades 988 28,248
11 -HVAC -Dedicated Outdoor Air System (DOAS)3,054 21,141
12 -Insulation -Basement Sidewall Installation 2,933 20,698
13 -Space Heating -Heat Recovery Ventilator 5,128 20,274
14 -High-Bay Lighting 4,123 19,394
15 -Windows -Low-e Storm Addition 2,832 18,790
16 -Furnace -Conversion to Air-Source Heat Pump 639 15,407
17 -High-Bay Lighting 6,056 14,687
18 -General Service Lighting 3,181 13,705
19 -Interior Lighting -Embedded Fixture Controls 2,470 13,523
20 -Connected Line-Voltage Thermostat 1,817 13,433
Total of Top 20 Measures 86,126 603,105
190,351 1,316,823
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 369 of 1105
| 21Applied Energy Group · www.appliedenergygroup.com
WA & ID Technical Achievable Potential by 2031SUPPLY CURVES
$-
$0.20
$0.40
$0.60
$0.80
$1.00
- 500,000 1,000,000 1,500,000 2,000,000
Levelized
Cost of
Energy
($/kWh)
Cumulative Savings (MWh)
TRC Conservation Supply Curve, 2031
Achievable Technical Potential Technical Potential
$-
$0.20
$0.40
$0.60
$0.80
$1.00
- 500,000 1,000,000 1,500,000 2,000,000
Levelized
Cost of
Energy
($/kWh)
Cumulative Savings (MWh)
UCT Conservation Supply Curve, 2031
Achievable Technical Potential Technical Potential
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 370 of 1105
| 22Applied Energy Group · www.appliedenergygroup.com
Top Measure Notes
•Some expensive or emerging measures have significant potential, but may not be selected by the IRP due to costs
•Heat Pump measures, including DHPs and HPWHs, have significant
annual energy benefits, however since heat pumps revert to electric
resistance heating during extreme cold, they do not have a corresponding winter peak benefit
•In addition to being expensive, some emerging tech measures are
included in Technical Achievable which may not prove feasible for
programs at this time, but can be kept in mind for future programs, e.g.:
•Advanced New Construction –Zero Net Energy
•Connected Home Control Systems
EE POTENTIAL
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 371 of 1105
| 23Applied Energy Group · www.appliedenergygroup.com
Top Measures -Winter Peak (MW) Reduction
by 2031
2031
MW
% of
Total
1 -ENERGY STAR -Connected Thermostat
2 -Windows -High Efficiency/ENERGY
3 -Windows -Cellular Shades
4 -Insulation -Basement Sidewall
5 -Windows -Low-e Storm Addition
6 -Home Energy Management System
7 -Connected Line-Voltage Thermostat
8 -Linear Lighting
9 -Building Shell -Air Sealing (Infiltration
10 -Insulation -Floor Upgrade
11 -Ducting -Repair and Sealing
12 -Insulation -Floor Installation
13 -Water Heater <= 55 Gal
14 -Insulation -Ducting
15 -Ducting -Repair and Sealing -Aerosol
16 -Building Shell -Liquid-Applied
-Resistive Barrier
17 -Fan System -Equipment Upgrade
18 -Retrocommissioning
19 -Building Shell -Whole-Home Aerosol
20 -Strategic Energy Management
Total of Top 20 Measures 95 70.9%
Total Cumulative Savings 134 100.0%
Peak Impacts –Technical Achievable Potential
Top Measures -Summer Peak (MW)
Reduction by 2031
2031
MW
% of
Total
1 -Retrocommissioning
2 -ENERGY STAR -Connected Thermostat
3 -Windows -High Efficiency/ENERGY STAR
4 -Windows -Cellular Shades
5 -Ductless Mini Split Heat Pump (Zonal)
6 -Strategic Energy Management
7 -Whole-House Fan -Installation
8 -Room AC -Removal of Second Unit
9 -Home Energy Management System
10 -HVAC -Dedicated Outdoor Air System
11 -Insulation -Ceiling Installation
12 -RTU -Evaporative Precooler
13 -Linear Lighting
14 -Ductless Mini Split Heat Pump with
15 -Insulation -Wall Sheathing
16 -Chiller -Variable Flow Chilled Water
17 -Central AC
18 -Building Shell -Liquid-Applied Weather-
19 -RTU -Advanced Controls
20 -Behavioral Programs (Incremental)
Total of Top 20 Measures 128 58.7%
Total Cumulative Savings 218 100.0%
EE POTENTIAL -CONTINUED
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 372 of 1105
| 24Applied Energy Group · www.appliedenergygroup.com
WA –TAP by Bundled $/kWhCOST OF SAVINGS
Washington
TRC $/kWh 2022 2023 2031
< $0.00
$0.00 -$0.05
$0.06 -$0.10
$0.11 -$0.20
$0.21 -$0.30
$0.31 -$0.40
$0.41 -$0.50
$0.51 -$0.75
$0.76 -$1.00
$1.01 -$1.50
$1.51 -$2.00
> $2.00
< $0.00
$0.00 -$0.05
$0.06 -$0.10
$0.11 -$0.20
$0.21 -$0.30
$0.31 -$0.40
$0.41 -$0.50
$0.51 -$0.75
$0.76 -$1.00
$1.01 -$1.50
$1.51 -$2.00
> $2.00
0
100,000
200,000
300,000
400,000
<$0 $0.05 $0.10 $0.20 $0.30 $0.40 $0.50 $0.75 $1.00 $1.50 $2.00 >$2
MWh
$/kWh
WA TAP by Cost Bundle -2031
TRC
UCT
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 373 of 1105
| 25Applied Energy Group · www.appliedenergygroup.com
ID –TAP by Bundled $/kWhCOST OF SAVINGS
Idaho
TRC $/kWh 2022 2023 2031
< $0.00
$0.00 -$0.05
$0.06 -$0.10
$0.11 -$0.20
$0.21 -$0.30
$0.31 -$0.40
$0.41 -$0.50
$0.51 -$0.75
$0.76 -$1.00
$1.01 -$1.50
$1.51 -$2.00
> $2.00
< $0.00
$0.00 -$0.05
$0.06 -$0.10
$0.11 -$0.20
$0.21 -$0.30
$0.31 -$0.40
$0.41 -$0.50
$0.51 -$0.75
$0.76 -$1.00
$1.01 -$1.50
$1.51 -$2.00
> $2.00
0
100,000
200,000
300,000
400,000
<$0 $0.05 $0.10 $0.20 $0.30 $0.40 $0.50 $0.75 $1.00 $1.50 $2.00 >$2
MWh
$/kWh
ID TAP by Cost Bundle -2031
TRC
UCT
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 374 of 1105
| 26Applied Energy Group · www.appliedenergygroup.com
EE POTENTIAL, CONTINUEDPotential Summary –Washington, All Sectors
2022 2023 2024 2031 2041
Baseline projection (GWh)5,196 5,212 5,229 5,479 6,243
Cumulative Savings (GWh)
Achievable Technical Potential 56 121 194 868 1,309
Technical Potential 101 209 325 1,247 1,822
Cumulative Savings (aMW)
Achievable Technical Potential 6 14 22 99 149
Technical Potential 12 24 37 142 208
Cumulative Savings as a % of Baseline
Achievable Technical Potential 1.1%2.3%3.7%15.8%21.0%
Technical Potential 2.0%4.0%6.2%22.8%29.2%
-
200
400
600
800
1,000
1,200
1,400
1,600
2022 2025 2028 2031 2034 2037 2040 2043
Cumulative TAP Savings (GWh) by Sector
Residential Commercial Industrial
0%
5%
10%
15%
20%
25%
30%
35%
2022 2023 2024 2031 2041
% of
Baseline
Cumulative Electric Savings
Achievable Technical Potential Technical Potential
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 375 of 1105
| 27Applied Energy Group · www.appliedenergygroup.com
EE POTENTIAL, CONTINUEDPotential Summary –Idaho, All Sectors
2022 2023 2024 2031 2041
Baseline projection (GWh)2,646 2,650 2,653 2,713 2,951
Cumulative Savings (GWh)
Achievable Technical Potential 33 70 110 448 665
Technical Potential 58 119 183 654 948
Cumulative Savings (aMW)
Achievable Technical Potential 4 8 13 51 76
Technical Potential 7 14 21 75 108
Cumulative Savings as a % of Baseline
Achievable Technical Potential 1.2%2.6%4.1%16.5%22.5%
Technical Potential 2.2%4.5%6.9%24.1%32.1%
-
200
400
600
800
1,000
1,200
1,400
1,600
2022 2025 2028 2031 2034 2037 2040 2043
Cumulative TAP Savings (GWh) by Sector
Residential Commercial Industrial
0%
5%
10%
15%
20%
25%
30%
35%
2022 2023 2024 2031 2041
% of
Baseline
Cumulative Electric Savings
Achievable Technical Potential Technical Potential
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 376 of 1105
Comparison with 2018 Electric CPA
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 377 of 1105
| 29Applied Energy Group · www.appliedenergygroup.com
Comparison with Prior Potential Study
We are often asked to compare results between current and prior potential study estimates –it is important to define comparison parameters.
Aligning calendar years, rather than study years results in a more thorough comparison
•This is mainly due to things like equipment standards, which come on by calendar year, not relative to the start year of the study
Since we are not estimating potential in 2021, potential for that year must be removed from the comparison
•First-Year Incremental Potential -2022
Prior Study: 2nd year of potential
Current Study: first year
The previous study’s 20-year look ended in 2040, therefore we must remove2041-2045 from the comparison
•Cumulative Potential Comparisons –2022 through year 2040
This should have a minimal impact on potential since retrofits are mainly captured prior to this point
As a result, we can draw up to a 19 year comparison (2022-2040)
NOTES ON COMPARISON
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 378 of 1105
| 30Applied Energy Group · www.appliedenergygroup.com
ACHIEVABLE POTENTIAL COMPARISONComparison with Prior Potential Study (2022-2037 TAP)
Sector End Use Prior CPA
2040 MWh
Current Study
2040 MWh Diff.(All States)
Residential
Cooling 74,528 112,573 38,045
Heating 444,182 442,897 -1,285
Water Heating 267,144 217,843 -49,301
Interior Lighting 63,331 24,122 -39,209
Exterior Lighting 10,059 4,122 -5,937
Appliances 91,966 82,297 -9,668
Electronics 49,899 58,651 8,752
Miscellaneous 35,248 45,661 10,413
Commercial
Cooling 99,708 145,262 45,554
Heating 33,372 100,989 67,617
Ventilation 73,363 116,241 42,878
Water Heating 22,078 26,182 4,104
Interior Lighting 261,940 210,469 -51,471
Exterior Lighting 103,244 61,188 -42,057
Refrigeration 42,103 119,602 77,499
Food Preparation 0 8,517 8,517
Office Equipment 3,805 14,945 11,139
Miscellaneous 2,018 10,216 8,198
Industrial
Cooling 6,160 4,779 -1,381
Heating 11,042 566 -10,476
Ventilation 7,942 11,679 3,736
Interior Lighting 52,125 49,781 -2,344
Exterior Lighting 12,428 5,213 -7,215
Motors 33,106 69,081 35,975
Process 10,059 7,012 -3,047
Miscellaneous 671 775 104
Grand Total 1,811,520 1,950,662 139,142
-
200
400
600
800
1,000
1,200
1,400
2021 2022 2023 2030 2040
GWh
Washington All-Sector TAP Comparison
Current Study
Prior Study (2021)
Prior Study (2022-2040)
-
100
200
300
400
500
600
700
2021 2022 2023 2030 2040
GWh
Idaho All-Sector TAP Comparison
Current Study
Prior Study (2021)
Prior Study (2022-2040)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 379 of 1105
| 31Applied Energy Group · www.appliedenergygroup.com
SECTOR-LEVEL ACHIEVABLE POTENTIAL
Washington -Comparison with Prior Study –Technical Achievable
•2020 savings already removed from prior study values
-
100,000
200,000
300,000
400,000
500,000
600,000
700,000
800,000
2022 2025 2030 2035 2040
MWh
Residential
Prior Study
Current Study
-
50,000
100,000
150,000
200,000
250,000
300,000
350,000
400,000
450,000
500,000
2022 2025 2030 2035 2040
MWh
Industrial
Prior Study
Current Study
-
100,000
200,000
300,000
400,000
500,000
600,000
2022 2025 2030 2035 2040
MWh
Commercial
Prior Study
Current Study
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 380 of 1105
| 32Applied Energy Group · www.appliedenergygroup.com
SECTOR-LEVEL ACHIEVABLE POTENTIALIdaho -Comparison with Prior Study –Technical Achievable
•2020 savings already removed from prior study values
-
100,000
200,000
300,000
400,000
500,000
600,000
700,000
800,000
2022 2025 2030 2035 2040
MWh
Residential
Prior Study
Current Study
-
50,000
100,000
150,000
200,000
250,000
300,000
350,000
400,000
450,000
500,000
2022 2025 2030 2035 2040
MWh
Industrial
Prior Study
Current Study
-
100,000
200,000
300,000
400,000
500,000
600,000
2022 2025 2030 2035 2040
MWh
Commercial
Prior Study
Current Study
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 381 of 1105
| 33Applied Energy Group · www.appliedenergygroup.com
Comparison with Prior Potential Study –Technical Achievable
Residential:
•LED share of interior lighting market baseline continues to grow, reducing
available potential from turnover of old units
This limits the extra potential Idaho gets from not having the EISA backstop in place
•HPWH savings have been revised slightly downward
•Decreases in interior lighting potential as base LED share grows in interior
lighting; accelerated turnover and ramp rate compensates, but not completely
•Increased refrigeration potential from new and emerging measures, updated
RTF workbooks
•HVAC retrocommissioning and controls (e.g. Strategic Energy Management systems) greatly expanded applicability in 2021 plan compared to prior study
•Increased potential in motors from updated retrofit applicability in 2021 plan
SECTOR-LEVEL NOTES
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 382 of 1105
| 34Applied Energy Group · www.appliedenergygroup.com
NEXT STEPS
•AEG has provided measure list and assumption appendices for EE to
Avista for circulation
•Electric IRP will evaluate cost effective portfolio based on AEG provided savings and levelized costs
•Gas IRP will run with AEG-provided UCT cost effective potential
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 383 of 1105
THANK YOU!
Ingrid Rohmund, Sr. Vice President, [e-mail]
Ken Walter, Project [e-mail]
Kelly Marrin, Managing Director
[e-mail]
Tommy Williams, Lead Analyst
[e-mail]
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 384 of 1105
Supplemental Slides
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 385 of 1105
| 37Applied Energy Group · www.appliedenergygroup.com
NWPCC 2021 PLAN RAMP RATES
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 386 of 1105
| 38Applied Energy Group · www.appliedenergygroup.com
•Several residential categories were adjusted to faster ramp rates
•C&I changes mostly slowed adoption, except for lighting which is greatly accelerated and non-equipment HVAC (maintenance, tune ups, etc) which accelerated
EE RAMP RATE CHANGES
Legend:
Faster Ramp
Slower Ramp
No Change
*compared to 2019
CPA Ramps
Sector(s)Measure Category Equipment or Non-Equip 2019 CPA Ramp Rate 2021 Plan Ramp Rate
Res Appliances Equipment LO1Slow LO12Med
Non-Equipment Retro12Med Retro5Med
Non-Equipment Aerators: Retro3Slow, SH:
Ret12Med
Retro3Slow
Equipment LO5Med CAC, LO1Slow RAC LO5Med CAC,
Non-Equipment Thermostat&DHP Retro5Med,
Retro3Slow
Thermostat&DHP
Retro5Med, Retro5Med
Equipment LO12Med & LO20 Fast LO20Fast
Equipment LO3Slow LO5Med
Non-Equipment LOEven20 NA
Non-Equipment Retro3Slow Retro3Slow
Sector(s)Measure Category Equipment or Non-Equip 2019 CPA Ramp Rate 2021 Plan Ramp Rate
C&I Building Shell Non-Equipment RetroEven20 Retro1Slow
Both Retro5Med, Retro12Med Retro5Med, Retro12Med
Non-Equipment Retro12Med Retro5Med
Equipment LO5Med, LO12Med LO3Slow, LO1Slow
Equipment LO5Med, LO20Fast LO5Med, LO12Med
Non-Equipment RetroEven20, Retro12Med,
Retro3Slow, Retro1Slow
Retro12Med,Retro5Med
Non-Equipment Retro12Med mostly RetroEven20
Equipment LO20Fast/LO50Fast LO80Fast
Non-Equipment Retro12Med Retro12Med
Both Retro12Med Retro5Med
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 387 of 1105
| 39Applied Energy Group · www.appliedenergygroup.com
Cumulative and Incremental
Over the following slides, we will display potential both as a impact on baseline as well as in annual
potential includes the impacts of potential acquired from the
first year of the study period (2022) through the year of interest, including
effects of measures persistence
potential summarizes new impacts realized in any given year
of interest, excluding the effects of measure repurchases
DEFINITIONS OF POTENTIAL
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 388 of 1105
Electric Wholesale Market Price Forecast
James Gall, Electric IRP Manager
Third Technical Advisory Committee Meeting
September 29, 2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 389 of 1105
Market Price Forecast – Purpose
•Estimate “market value” of
resources options for the IRP
•Estimate dispatch of “dispatchable”
resources
•Helps estimate avoided costs
•May change resource selection if
resource production is counter to
needs of the wholesale market
Source: NERC
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 390 of 1105
-$100
-$50
$0
$50
$100
$150
$200
$250
$300
$350
0 10,000 20,000 30,000 40,000 50,000
$
p
e
r

M
W
h
Capability (MW)
Hydro (Must Run for Negative Pricing)
CCCT
Peakers
Demand
Hydro Availability
Fu
e
l

P
r
i
c
e
s
/
V
a
r
i
a
b
l
e

O
&
M
Other Resource Availability
Nuclear/ Co-Gen/ Coal/ Other
Wind (Net PTC/REC)
Market Price
Note: minimum price is negative $25/ MWh (2018$)
Methodology
3rd party software-Aurora by Energy
Exemplar
Electric market fundamentals-production
cost model
Simulates generation dispatch to meet
regional load
Outputs:
–Market prices (electric & emission)
–Regional energy mix
–Transmission usage
–Greenhouse gas emissions
–Power plant margins, generation levels, fuel
costs
–Avista’s variable power supply costs
3
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 391 of 1105
Wholesale Mid-C Electric Market Price History
13
23 23
117
126
22
38 42
58
45
51
59
32 33
23 19
32 33
23 20 22
30 36
22
30 29 29 28
$0
$20
$40
$60
$80
$100
$120
$140
19
9
7
19
9
8
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
Cheap
Natural
Gas, good
hydro
Energy Crisis
Natural Gas Market Tightens
Shale Development Forwards
as of
9/18/2020
4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 392 of 1105
U.S. Western Interconnect Generation Mix
Significant changes (aGW
Solar: + 5.0
Wind: + 6.2
Nat Gas: + 6.5
Coal: -9.3
Nuclear:-1.5
Total: + 11.0
Hydro: -4.2 / +5.2
-
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
100,000
2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
5 Source: EIA
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 393 of 1105
Northwest Generation Mix (ID, MT, OR and WA)
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Coal Natural Gas Hydro Nuclear Wind Solar Petroleum Other
Significant changes (aGW)
Solar: + 0.1
Wind: + 2.3
Nat Gas: + 2.0
Coal: -0.8
Total: + 5.7
Hydro: -3.7 / +3.5
2019 2.0 aGW less than
2002-2018 Avg
6 Source: EIA
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 394 of 1105
2019 Fuel Mix
Northwest
70% GHG Emission Free*
U.S. Western Interconnect
49% GHG Emission Free
Source: EIA
* Low hydro year dropped emission free statistic from 77% in 2018 to 70% in 2019 7
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 395 of 1105
$0
$10
$20
$30
$40
$50
$60
$70
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
$
p
e
r

M
W
h
Daily Mid-C Price Standard Deviation
Off Peak
On Peak
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
Po
w
e
r
/

G
a
s

x

1
0
0
0
Implied Market Heat Rate
y = 6.9043x + 9.4321R² = 0.9031
$0
$10
$20
$30
$40
$50
$60
$70
$0 $2 $4 $6 $8 $10
Mi
d
-C
$

p
e
r

M
W
h
Stanfield $ per DTh
Daily NG vs On-Peak Electric
4.57 6.13 7.02
3.89
7.95
3.62
7.24
4.43
(2.45)
1.30
7.71
4.54
6.92 5.16 4.19
13.12
16.55
-$5
$0
$5
$10
$15
$20
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
St
a
n
f
i
e
l
d

x

7

-
Mi
d

C
Spark Spread
Market Indicators-Market is Tightening
8
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 396 of 1105
US Western GHG Emission End Use
0
200
400
600
800
1,000
1,200
19
8
0
19
8
1
19
8
2
19
8
3
19
8
4
19
8
5
19
8
6
19
8
7
19
8
8
19
8
9
19
9
0
19
9
1
19
9
2
19
9
3
19
9
4
19
9
5
19
9
6
19
9
7
19
9
8
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
Residential Commercial Industrial Electric Power Transportation
Source: EIA
2017:
Transportation: 46%
Electric Power: 28%
Industrial: 15%
Commercial: 5%
9
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 397 of 1105
Electric Greenhouse Gas Emissions
U.S. Western Interconnect
0
50
100
150
200
250
300
350
Emissions are adjusted for generation within the Western Interconnect
2018 and 2019 estimates are subject to adjustment
Change
+5.9
+4.9+18.1
+10.3
-4.4
+1.9+9.2
+1.4
+11.4
-26.6+16.4
10
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 398 of 1105
Northwest Greenhouse Gas Emissions
MT WA OR ID
11
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 399 of 1105
The Forecast: 2022 to 2045
Deterministic Model
•Simulate based on average
conditions
•210,240 hours simulation
•Takes about 6 hours on one
processor
•Good approximation to estimate
impacts of assumptions-great for
scenario analysis, but not risk
•Output Files: 26 GB
Stochastic Model
•Simulate 500 varying conditions
•Fuel Prices, Loads, Wind, Hydro,
Outages, Inflation
•105 million hours of simulation
•Takes about 5 days on 33
processors
•Allows for full evaluation of
resource alternatives and accounts
for risk
•Output Files: 360 GB
12
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 400 of 1105
Modeling Process
Vendor Database
(2019 North American)
Input Changes
80 yr hydro
NG prices
Regional Loads
Avista Resources/Loads
Operational Detail
Capacity Expansion
Add new resource forecast
(Capacity/RPS)
Include known retirements
Model adds resources to meet planning targets
Test Year Stochastic Study
Test Resource Adequacy
Re-Run Capacity Expansion
Increase/Decrease Planning Margin Targets
Run Full Forecast
Stochastic & Deterministic
Run Scenarios
Deterministic
Stochastic (if necessary)
13
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 401 of 1105
Load Forecast
•Regional load forecast from ‘IHS
–Forecast includes energy efficiency
•Add net meter resource forecast
–Input annually with hourly shape
•Add electric vehicle forecast
–Input annual with hourly shape
•Future load shape to be different
then today’s load shape
14
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 402 of 1105
Electric Vehicle and Solar Adjustments
Roof Top Solar
•EIA existing estimates for history
•‘IHS regional growth rates
Electric Vehicles
•Penetration rates increase each year (2040 shown below)
•15-30% light duty
•12-15% medium duty
•5% heavy duty
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Me
g
a
w
a
t
t
s
15
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 403 of 1105
New Resource Forecast (Western Interconnect)
2025 2030 2035 2040 2045
CCCT 3.3 9.9 10.7 11.6 12.8
SCCT 15.4 17.8 19.3 20.2 22.7
DR 2.1 6.0 7.6 9.5 11.5
Storage 7.9 16.2 25.7 35.5 47.1
Net-Meter 4.5 6.5 8.5 10.8 13.9
Solar 25.5 37.5 47.8 59.7 73.0
Wind 7.8 15.7 24.1 33.4 43.3
Geothermal 0.3 0.7 1.2 1.9 2.9
Biomass 0.2 0.4 0.6 0.7 0.9
Hydro 1.3 1.6 1.9 2.4 2.8
-
50.0
100.0
150.0
200.0
250.0
Gi
g
a
w
a
t
t
s
16
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 404 of 1105
U.S. West Resource Type Forecast
17
-
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
100,000
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Significant changes
2045 to 2022 (aGW)
Solar: + 15.9
Wind: + 10.5
Nat Gas: -3.1
Coal: -11.9
Nuclear:-4.5
Other: + 1.5
Hydro:+ 0.3
Total: + 11.9
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 405 of 1105
Northwest Resource Type Forecast
18
-
5,000
10,000
15,000
20,000
25,000
30,000
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Significant changes (aGW)
2045 to 2022
Solar: + 2.9
Wind: + 2.4
Nat Gas: - 2.1
Coal: - 0.6
Other: + 0.7
Nuclear: - 1.1
Total: + 2.2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 406 of 1105
Mid-C Electric Price Forecast
•Levelized Prices:
–2022-45: $26.05/MWh
–2022-41: $23.03/MWh
•Off-peak prices over take
on-peak in 2024 on an
annual basis
•Evening peak prices
remain high (4pm-10pm)
19
$
p
e
r

M
W
h
Mid-Columbia Electric Forecast (Deterministic)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 407 of 1105
Mid-C Price Forecast (Stochastic- Draft)
20
$0
$10
$20
$30
$40
$50
$60
$70
$80
$90
$100
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
$
p
e
r

M
W
h
24-yr Levelized Prices
Mean: $27.11/MWh
Median: $24.84/MWh
Deterministic: $26.05/MWh
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 408 of 1105
Mid-C Electric Price Comparison vs. Previous IRPs
21 * These forecasts use price scenarios without GHG “taxes” to make all forecasts consistent
$
p
e
r

M
W
h
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 409 of 1105
Hourly Wholesale Mid-C Electric Price Shapes
-$25
$0
$25
$50
$75
$100
$125
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
$
p
e
r

M
W
h
Hour
Summer: Jun 16 -Sep 15
2022 2030 2035 2040 2045
22
$
p
e
r

M
W
h
Hour
Winter: Dec 16 -Mar 15
$
p
e
r

M
W
h
Hour
Spring: Mar 16 -Jun 15
$
p
e
r

M
W
h
Hour
Fall: Sep 16 -Dec 15
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 410 of 1105
Greenhouse Gas Forecast
U.S. Western Interconnect
23
Mi
l
l
i
o
n

M
e
t
r
i
c

T
o
n
s
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 411 of 1105
Greenhouse Gas Forecast
Northwest States
24
-
5
10
15
20
25
30
35
40
45
19
8
0
19
8
2
19
8
4
19
8
6
19
8
8
19
9
0
19
9
2
19
9
4
19
9
6
19
9
8
20
0
0
20
0
2
20
0
4
20
0
6
20
0
8
20
1
0
20
1
2
20
1
4
20
1
6
20
1
8
20
2
0
20
2
2
20
2
4
20
2
6
20
2
8
20
3
0
20
3
2
20
3
4
20
3
6
20
3
8
20
4
0
20
4
2
20
4
4
Mi
l
l
i
o
n

M
e
t
r
i
c

T
o
n
s
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 412 of 1105
Market Scenario Assumptions
•High Natural Gas Prices
–90th percentile of stochastic prices
using 1,000 draws
•Low Natural Gas Prices
–25th percentile of stochastic prices
using 1,000 draws
•Social Cost of Carbon “Tax”
–Western Interconnect Carbon “Tax” on
Generation
–SCC pricing beginning in 2025,
trending up beginning in 2022.
•Climate Shift
–Uses NWCC three climate futures
–Trend Northwest hydro and loads for
warming temperatures
–Lower NG CT capability due to
temperature change
$
p
e
r

D
e
k
a
t
h
e
r
m
25
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 413 of 1105
Climate Shift Methodology (Loads)
•Uses 2024 operating year
forecast.
•Overlays the 2020 to 2049
temperature forecast using
an average of three climate
models chosen by the
NPCC.
•Create a linear trend of load
based on changes in
weather*-referred to as
scalers.
•Apply scalers to expected
case load forecast.
* does not include secondary changes in load due to climate shift
Data & scalars provided by PNUCC
26
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 414 of 1105
Climate Shift Methodology (Hydro)
•NPCC provides 80-year hydro
history and three models with
30 years of potential hydro for
the 2040’s.
•Compare the average of three
climate models to the 80-year
hydro history.
•Linearly trend the change
between the beginning and the
end of the forecast.Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
27
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 415 of 1105
Scenario Results: Wholesale Electric Prices
Levelized Prices (2022-2045)
•Expected Case: $26.05/MWh
•Social Cost of Carbon: $58.56/MWh
•High NG Prices: $46.07/MWh
•Low NG Prices: $19.35/MWh
•Climate Shift: $25.51/MWh
28
$
p
e
r

M
W
h
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 416 of 1105
Scenario Results: US Western Interconnect GHG Emissions
187 196
179 187
169
126 128 122 125
100
85 83 83 83
68
0
50
100
150
200
250
Expected Case High NG Price Scenario Low NG Price Scenario Climate Shift Scenario Social Cost of CarbonScenario
Me
t
r
i
c

T
o
n
s

(
M
i
l
l
i
o
n
s
)
Market Forecast Scenario
2022 Average 2045
29
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 417 of 1105
Scenario Results: U.S. Western Interconnect Resource Type
ExpectedCase
Low NGPriceScenario
High NGPriceScenario
ClimateShiftScenario
SocialCost ofCarbonScenario
Solar 9,024 9,023 9,024 9,022 9,978
Wind 9,698 9,698 9,700 9,692 9,694
Natural Gas 17,785 19,394 16,002 17,788 19,158
Coal 14,870 13,160 16,783 14,886 12,164
Nuclear 7,188 7,187 7,195 7,178 7,185
Other 3,623 3,625 3,604 3,597 3,628
Hydro 19,570 19,570 19,570 19,570 19,571
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
100,000
Av
e
r
a
e
g

M
e
g
a
w
a
t
t
s
Year: 2022
ExpectedCase
Low NGPriceScenario
High NGPriceScenario
ClimateShiftScenario
SocialCost ofCarbonScenario
Solar 16,053 16,047 16,059 16,050 16,864
Wind 13,048 13,033 13,057 13,049 13,010
Natural Gas 16,411 17,126 16,094 16,267 19,170
Coal 9,699 8,935 9,973 9,670 4,874
Nuclear 4,426 4,416 4,432 4,424 4,440
Other 4,013 3,992 3,994 4,007 3,680
Hydro 19,568 19,568 19,568 19,694 19,568
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
100,000
Av
e
r
a
e
g

M
e
g
a
w
a
t
t
s
Year: 2030
ExpectedCase
Low NGPriceScenario
High NGPriceScenario
ClimateShiftScenario
SocialCost ofCarbonScenario
Solar 22,059 22,040 22,071 22,033 22,550
Wind 17,477 17,461 17,498 17,455 17,367
Natural Gas 14,489 14,782 13,997 14,255 15,309
Coal 4,477 4,251 4,535 4,410 2,069
Nuclear 4,729 4,713 4,740 4,714 4,727
Other 4,605 4,550 4,632 4,585 4,295
Hydro 19,726 19,726 19,726 20,028 19,726
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
100,000
Av
e
r
a
e
g

M
e
g
a
w
a
t
t
s
Year: 2040
30
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 418 of 1105
Incremental GHG Emissions for Energy Efficiency
•This IRP assumes GHG emissions from load
reduction and associated emissions from market
purchases/(sales)*
•2020 IRP assumes average emissions each year
based on average emissions compared to load
each year. (See blue bars)
•Avista believes average emissions best
represents the associated emissions for market
purchases/sales:
–Should this be based on load or generation?
•Avista is considering using incremental emissions
for valuing energy efficiency for Washington’s cost
analysis:
–Load or generation calculation method?
–Increase load vs. decrease load method (or average)?
–At what granularity to apply benefit?
* Purchases related to storage resources assumes a slightly different provide due to charging times
lb
s

p
e
r

M
W
h
Northwest Emission Intensity
(WA, OR, ID, MT, UT, WY)
31
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 419 of 1105
Data Availability
Outputs
•Expected Case: annual Mid-C
prices by iteration (stochastic)
•Expected Case: hourly Mid-C
prices (deterministic)
•Scenarios: monthly Mid-C electric
prices
•Regional resource dispatch
•Regional GHG emissions
•Avista resource dispatch data will
be included within PRiSM Model
Inputs (Not already Posted)
•Climate shift scaling factors for
load/hydro
•High/low natural gas prices
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 420 of 1105
2020 Electric Integrated Resource Plan
Draft Portfolio Scenario Analysis
John Lyons, Ph.D.
Third Technical Advisory Committee Meeting
September 29, 2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 421 of 1105
DRAFT
Portfolio Scenarios –2020 IRP
1. Preferred Resource Strategy
2. Least Cost Plan-w/o CETA
3. Clean Resource Plan: 100% net clean by 2027
4. Rely on energy markets only (no capacity or renewable additions) w/o CETA
5. 100% net clean by 2027, and no CTs by 2045
6. Least Cost Plan w/o pumped storage or Long Lake as options
7. Colstrip extended to 2035 w/o CETA
8. Colstrip extended to 2035 w/ CETA
9. Least Cost Plan w/ higher pumped storage cost
10. Least Cost w/ federal tax credits extended
11. Clean Resource Plan w/ federal tax credits extended
12. Least Cost Plan w/ low load growth (flat loads-low economic/population growth)
13. Least Cost Plan w/ high load growth (high economic/population growth)
14. Least Cost Plan w/ Lancaster PPA extended five years (financials will not be public)
Others: Efficient frontier portfolio (least risk, 75/25, 50/50, and 25/75)
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 422 of 1105
DRAFT
Portfolio Scenarios-2021 IRP
1.Preferred Resource Strategy
2.Baseline Portfolio 1 (No CETA renewable targets)
3.Baseline Portfolio 2 (No CETA renewable targets/SCC)
4.Clean Resource Plan (100% Portfolio net clean by 2027)
5.Clean Resource Plan (100% Portfolio clean by 2045)
6.Social Cost of Carbon applied to Idaho
7.Least Cost Plan-w/ low load growth
8.Least Cost Plan-w/ high load growth
9.Least Cost Plan-w/ Northwest Resource Adequacy Market Peak Credits
10.Heating Electrification Scenario 1
11.Heating Electrification Scenario 2
12.Heating Electrification Scenario 3
13.Least Cost Plan-w/ climate shift
14.Least Cost Plan-w/ 2x SCC prices
15.Colstrip serves Idaho customers through 2025
16.Colstrip serves Idaho customers through 2035
17.Colstrip serves Idaho customers through 2045
18.If necessary: CETA deliver to customers each hour
19.If necessary: other resource specific scenarios depending on outcome of PRS results
3
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 423 of 1105
TAC Meeting 3 Notes – September 29, 2020
Virtual Attendees: Shay Bauman, Shawn Bonfield, Annette Brandon, Terrence
Browne, Morgan Brummund, Michael Brutocao, Ethan Case, John Chatburn, Corey
Dahl (Public Counsel), Michael Eldred (IPUC), Chip Estes, Ben Fadie, Rachelle
Farnsworth (IPUC), Ryan Finesilver, Damon Fisher, James Gall, Amanda Ghering, GS,
Guest (5), Leona Haley, Lori Hermanson, Jan Himebaugh (BIAW), Elizabeth Hossner,
Tina Jayaweera, Clint Kalich, Kathlyn Kinney, Dean Kinzer, Melissa Kuo, Scott Kinney,
John Lyons, Fred Heutte (NWEC), Jaime Majure, Kelly Marrin, Stuart M., Eli Morris,
Katie Pegan, Tom Pardee, Jorgen Rasmussen, Jeff Schlect, Jennifer Snyder (WUTC),
Darrell Soyars, Collins Sprague, Dean Spratt, State of Idaho, Jason Thackston,
Unavailable (1), Ken Walter (AEG), Tom Williams, Katie Ware, and Yao Yin (IPUC).
Notes in italics after questions were made by the presenter.

IRP Transmission Planning Studies – Dean Spratt, Avista
Yao Yin (Slide 15): When Avista contracts with a QF [qualifying facility under PURPA],
does the QF contract for transmission at the same time? Probably a better merchant
question. It was studied by us and neighboring utilities. They typically don’t have tools to
conduct full qualified studies. Does that help? Yes, thank you.
Dean Spratt: Regarding QF versus non-QF impacts, these are studied by us [Avista
transmission] and others. The scope is different for these.
Yao Yin (Slide 16): Does a QF get into the same queue regarding scope of the project?
Dean Spratt: Yes. Anyone, QF or not, that wants to get on the system has to go
through the [same] interconnection process. A QF or large project has to go through the
interconnection request. There is one queue that captures everything. Transmission
planning only sees the larger projects. It could be a cut-off for smaller projects. There
are different rules for different states.
Jeff Schlect: I’m going to chime in here. I’m the Senior Manager of Transmission
Services here at Avista. Yes, all projects work through the same queue under FERC or
by state agreement based on the size of the project. There is one queue for all sizes,
but they could be subject to a FERC process or to some other process.
Yao Yin: Thanks Jeff. I was unsure of the small project cut off.

Distribution Planning within the IRP – Damon Fisher, Avista
Jennifer Snyder: HB 1126 has been codified in RCW 19.280.100.
Rachelle Farnsworth: Talk about how and if the company is looking at smart inverters
and how you will use those?
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 424 of 1105
Damon Fisher: Latest IEEE. Yes, but how planning is going to integrate remains to be
seen. I don’t think the hardware has caught up with the standard yet, maybe by 2021 or
2022. We are not quite there. We would implement that as stated in the new 1547 right
through. There are concerns with transmission faults in Germany and California where a
lot of load was dropped due to the large amount of inverters and them not recognizing it
was a short trip and needed to stay online longer. A distribution fault drops all
generation and transmission fault stays online longer.
Rachelle Farnsworth: Yes, I was just curious on smart inverter policy and settings.
Where is the company on developing a policy on this?
Damon Fisher: Existing 1547 is what we are following. New 1547 is the ride through
ability. Thank you. That is system protection and I’m not an expert on it.
Kathlyn Kinney: Is there something outward facing where you publicize where grid
issues are and where DR is needed?
Jennifer Snyder: Do you have studies on where DR would be helpful?
Damon Fisher: No, there isn’t yet. We’ve been working hard to get modeling for
facilities hosting capacity for load and later generation. There are lots of benefits
internally for guiding new load to where it doesn’t create system constraints. Lots of
work is being done on these maps with this intent. Can approach more sophisticated
customers first with incentives to help with grid constraints. Some of these studies are
out there, such as the work done in New York. I will send a link. If anyone is interested,
New York has one that is pretty interesting. New York was able to work through it.
There are a few studies out there.
Damon Fisher (Slide 14): 15 days in December, it’s dark before 4 pm back in the old
days when we went to work. Something that would give me pause would be to just use
solar to fix a grid issue when there are situations like that.
Damon Fisher (Slide 15): Will drastic changes in the day cause a problem as a grid fix
issue? Need data and studies. What if we fix the curve with a battery or use two DERs?
Maybe we just go straight to a battery. All of these are considerations in fixing the gird
and adding resources when available to the system.
Damon Fisher (Slide 17): Blue is transmission. Orange is the 230 kV lines. BPA is in
there as well. Airway Heights is a big growth area. We don’t serve the new Amazon
facility directly, but local growth in the area is occurring through our substation feeders
nearby and they are approaching their limits.
Yao Yin (slide 19): I’m not very familiar with the concept of hosting capacity. What does
that mean?
Damon Fisher: Our system can host your generation. Like 5 MW of solar. We can do
pre-analysis of the system with gobs and gobs of analysis to show constraints on a
map. If it’s in a development and you want to put in 1 MW of solar, where can I get it
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 425 of 1105
attached quicker? I can also do that for load. Pre-analysis of where you can add more
resources without causing system problems. Load is also interesting. Generators who
might be interested in hosting solar or whatever generation on our system. You run
through scenarios of attached generation and look for constraints such as high voltage
problems. Map can then be geo-referenced that tells generators of where you can
locate projects. Possibly to do pre-analysis to shorten Dean’s queuing process. Intend
to do this with load and generation and where to locate generation without causing
problems.
Yao Yin: Does that consider upgrades only for existing or does it assume upgrades
happen?
Damon Fisher: Yes. Run analysis until you encounter the first constraint. If done
correctly, you can do a hosting map that will guide these projects without requiring
system investment. Hosting capacity map will go stale when resources are added. Easy
to go stale if maps aren’t maintained. How often do you do this? It could be a resource
intense operation. Possibly automate it, but that remains to be seen.
Damon Fisher (Slide 19): AMI data is 5 minutes out of the meters. Can apply various
techniques to the data to pick out what load is occurring. Where are we getting electric
vehicles as more of them are out there? Will we have less visibility of where they are
and what they are doing to the system as they are charging? Can look for the most
offensive user of energy or demand (AC) and then target those as a DER candidate.
This causes all sorts of weird questions on tariffs, targeting, etc. For northwest utility
DERS, this is an enlightening conversation with everyone. What is right, appropriate,
average and above average?

Demand Response Potential Assessment – Kelly Marrin, AEG
Kelly Marrin: This Demand Response (DR) Potential Assessment shows the preliminary results. It is not the first round, but is not finished yet.

Brian Fadie (Slide 11): The first note under sources mentions an Avista proposed cycling strategy for DLC Central AC and Smart Thermostats (cooling). Can you describe that further?

Kelly Marrin: The Power Plan has something closer to 1, when talking to Avista about
what they might use, they said they’d implement something more moderate so AEG
adjusted this down.

Kathlyn Kinney: On the percentage with EV charging, what is getting measured? Is it a percentage over the top and will this be changing over the year, what exactly is being measured here?

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 426 of 1105
Kelly Marrin: This is an average per customer reduction per event and accounts for all participants whether they’re plugged in or charging. As EV penetration increases, megawatts will go up and that’ll show up in EV saturation. Impacts start low, but by
2045 they will be substantial as we have more EVs.

Yao Yin: Any assumptions regarding battery duration and efficiency?

Kelly Marrin: We will provide more detail on technical research done on batteries. We
have six hours storage assumed per day and 8 hours for larger batteries.

Tina Jayaweera: There a number of electrification scenarios in the IRP, have you incorporated that in your work?

Kelly Marin: We are not doing any scenarios. We are using the same forecast.

James Gall: From energy efficiency, those electrification scenarios already include
them. We have not discussed DR yet, but will discuss this when our studies are
complete. Tina thanks for reminding us to circle back and do that analysis.

Yao Yin: Big picture, if a technology is used for ancillary services does it hurt the chance for it to serve other purposes? For example, a battery. Are these two mutually exclusive?

Kelly Marrin: That’s right. Ancillary service doesn’t always have a specific time, so we
don’t add these and don’t stack the value of ancillary services on top of the capacity. If
there’s an overlapping event. Ancillary services are not at a specific time, they can be at
any time of the year or day. We never add these to the other programs. This loads first.
Capacity is looked at separately and in a particular order. They account for not calling
the same load at the same time but for ancillary service. It’s a completely different load
and we assume this doesn’t happen during system peak event times.

Yao Yin: So there is an order?

Kelly Marrin: Yes, could do either one, but not both.

Damon Fisher: Have any of the grid limitations been taken into consideration? All
batteries operating on a feeder at the same time that cause voltage whip-sawing if they
are on all at once?

Kelly Marrin: We haven’t gone into that level of detail. This is a broad brush study, less
broad than before, but take it with the idea of trying to get a sense of what the potential
could be. But we haven’t looked at it at the technical level of response.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 427 of 1105
Damon Fisher: The feeder itself could be at the limit itself, not the technical potential.

Kathlyn Kinney: At a high level, how does this compare to increasing electricity
demand over time? How close are we to breaking even?

Kelly Marrin: Haven’t gotten to that step yet. If we add up all of the DR reductions
versus the forecast. We haven’t gotten to that step yet, but when we add up at a very
high level of the percentage – I think close to 10%, but 5 – 10% of total peak demand by
2045.

Kathlyn Kinney: Do we know what the increase from electrification will be?

James Gall: It’s available on the website, but is about 800 MW over the next 24 years.
If we did all these programs, we can offset more than our load growth. DR is only for
those couple of hours. We still have the rest of the year to deal with.

Fred Heutte: I just came in from another call I had to run to. DR is a key interest these
days. Specifically, we think the new standard grid-integrated water heaters will provide a
lot of savings. We are very interested in utilities trying to show this. How many electric
water heaters are now in the Avista service territory? We’ve seen increasing periods of
very high pricing at Mid-C and elsewhere. Will that be folded into the value of DR?

Ken Walter: The water heater number is not in front of me, but we could map it.

Fred Heutte: 45-55% in the region. It is helpful to know. I’ve looked at the saturation
assessments, but don’t know for sure. My guess over time is a high number above 50%.

James Gall: That is the plan. We’ll assign a price to call on DR. From a modeling
perspective, it’s difficult, it will need to be done outside of the model. Not sure of the
price yet, so there is a market opportunity to take advantage of. It is not impossible to
model, but very difficult.

Fred Heutte: Lots of different factors with coal retirements and limited DR now.

Tina Jayaweera: For the transmission and distribution side, how can DR help with this
and what we heard earlier? Haven’t finished with costs for both T&D particulars.

Kelly Marrin: A question we need to address together when we get there. Sounds like
there could be additional value from geographic-specific DR. Definitely on the location
specific side. Will make a note of that for when we get there and will revisit with Avista
when we get there.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 428 of 1105
Conservation Potential Assessment – Ken Walter, AEG
Tina Jayaweera: Is the T&D deferral being incorporated here?
Ken Walter: It’s being incorporated in the avoided cost. I’ll ask Ryan if he remembers.
It’s not an exact value. We are looking into how to have a more prospective approach to
historic value of the net plant value for T&D deferral.
Tina Jayaweera: The Council has a proposed methodology, I can’t remember if Avista
used that?
Ryan Finesilver: No, it wasn’t used but we’d be happy to talk about it.
Tina Jayaweera: Ok, we can talk about it offline.
Brian Fadie: Is the social cost of carbon being considered in these cost effectiveness tests?

James Gall: Yes, we include it for incremental energy efficiency. There will be more
emissions avoided somewhere else in the region. There is a slide on that later today.
More energy efficiency and more incremental emissions are avoided and we would
include that benefit.

Yao Yin (Slide 14): In the load and resource balance, which line is used to determine
the amount of energy efficiency?
Ken Walter: The middle green line, but we provide savings at the measure level. About
7,000 line items.
James Gall: The load forecast which we show there is reduced somewhere between
the red and the hashed lines. Energy efficiency programs that are cost-effective will
reduce that load.
Grant Forsyth: Forecast without energy efficiency included, run PRiSM, and then I
gross up the forecast for energy efficiency that could be existing in the future.
James Gall: Yes, it’s a circular chicken and egg issue as we don’t know what programs
will be used in the future. The idea is to get a forecast of programs that are cost
effective to increase or decrease loads, then iterate between the two. Start with a high
load forecast, select energy efficiency programs with PRiSM, and then redo the forecast
with and without energy efficiency for energy and for peak load.
Yao Yin: In Grant’s forecast without energy efficiency, PRiSM is then used to select and
adjust that load. How does this slide fit into that process (slide 14)?
James Gall: There are a number of programs that are available to be selected as to
whether they should move forward or not.
Ken Walter: Pool of all measures is what the model selects from.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 429 of 1105
Richard Keller: Is slide 14 in GWh, not aMW? Yes, GWh. Thanks.
Tina Jayaweera: Catching up with industrial customers in your assessment, are those
two large industrial customers eligible for energy efficiency programs?
Ryan Finesilver: I believe all customers are eligible. All customers pay into the
efficiency program. So I guess the question is how we are accounting for industrial
customers in the IRP? They are not in the baseline. The problem is we can’t apply a
curve to a single individual customer. The large industrial company makes its own
energy efficiency decisions, which is not something we can do on a model level.
James Gall: We need to take this issue back as a group internally and discuss it.
Tina Jayaweera (slide 15): How are you accounting for the missed energy efficiency
for these two customers?
Ryan Finesilver: Assume that their efficiency will be included as well.
Ken Walter: Not in baseline so not included. Can’t apply a curve designed for a whole
population to a single individuals. Other clients have approached this by having AEG
speak to these customers and see what they intend to do.
James Gall: Sounds like we need to discuss this internally.
Ken Walter: Tina, thanks for the idea.
Tina Jayaweera: How are you determining the peak impact for energy efficiency?
What is the methodology?
Ken Walter: The ratio of peak kW to annual kWh based on end use shapes on an
hourly level. We use that to segment.
Tina Jayaweera: For load shapes, what are your main sources?
Ken Walter: Open EI and I think the Yakima weather station.
Yao Yin: When are the peak hours for Avista for both winter and summer?
James Gall: 7-8 am in morning or 5-6 pm in the evening for the winter. Summer peaks
around 4 pm or 6 to 7pm. summer peak usually occurs in July or August and winter is in
the end of November through mid-February. The days of the week also matter, Monday
through Wednesday are usually the highest load. Some peak weather events occur on
holidays or weekends when loads are lower.
Yao Yin: What is the method used to determine peak hours?
James Gall: Looking at actual load history.
Tina Jayaweera: For energy efficiency do you take the average or the peak?
Ken Walter: We do it based on the actual single peak hour.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 430 of 1105
Yao Yin: I’m a little confused, is it the single peak hour, not a period but one hour?
James Gall: Yes, we assume it as a single hour as opposed to an average over 2 to 3
hours.
Yao Yin: How did you determine which hour?
James Gall: For each month, Grant looks at the hottest and coldest day of the month
and averages the historic weather years to come up with a peak hour.
Yao Yin: That results in one single peak hour instead of the timeframes you mentioned
earlier?
James Gall: Our modeling is at the annual peak perspective. We are not looking at
when that specific hour is. We are given a high water mark and then looking at
measures to reduce it from there. Value we are looking at is an average. The future is
an expectation of what that will change to.
Tina Jayaweera: The IRP is an hourly model. Are you taking 8760 hours from energy
efficiency? The peak from here doesn’t actually get used. Is that correct?
James Gall: The 8760 is used for the economic analysis of energy valuation for how
much energy is worth. We get a summer and a winter peak value. Evaluate on energy
and then how much it lowers winter or summer peak value for the L&R.
Tina Jayaweera: Confused about peak of a couple of hours versus what we have here.
James Gall: We don’t know a specific hour when it will occur.
Tina Jayaweera: That makes sense and it can shift around. My concern is on the
energy efficiency side, it’s over or under estimating because it’s not just one hour.
Ken Walter: How a peak event breaks down across end use typically won’t be
materially different so there is not much risk of over or under estimating.
Tina Jayaweera: My concern is with winter, if it occurs in the morning versus the
evening, equipment operates differently. I don’t know how impactful this would be, just
exploring.
Ken Walter: I’m making a note on that.
James Gall: No model can evaluate every hour so that the model can solve. We don’t
know the specific hour when a peak will occur. It is not a consistent hour for every day.
All inputs are available on our website in the same format I used in the IRP.

Electric Market Price Forecast, James Gall
Richard Keller (slide 4): Is this the average annual price?

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 431 of 1105
James Gall: Yes, for on peak and off peak.

Richard Keller: How does the model look at hourly reliability attributed to operating
reserves?

James Gall (slide 12): The model is solving for operating reserves on a system basis
for an area or zone and not on a utility basis. Six percent operating/spinning and non-
spinning reserves and 2% for regulation. Hopefully, that helps.

Fred Heutte: A lot of data there. I’m not terribly surprised with trying to take into account all of the things in the stochastic model. There is a jump logic approach to shock parameters, I’m wondering if you do something like that to pick up a COVID or such an event. PAC does something similar.

James Gall: Not specifically, but there are specific tail shock events that do occur. A
black swan event is great to test as a scenario. They show up, but not at the same time.
Stochastic modeling tries to take into account an event like those tail events.

Yao Yin (slide 12): Is there an algorithm that calculates whether the wind/solar can be
integrated?

James Gall: There is not a specific requirement looking at the instantaneous number. There is not a dynamic reserve held for winter. It holds back capacity for integration based on the inputs. We can model this in the future, but it probably wouldn’t solve in time to be useful as it would slow the model to a crawl. The model wouldn’t solve in enough time to be usable. Maybe the technology will get better so it could solve.

Yao Yin: Is the amount of reserve percentage manually entered?

James Gall: Yes, for price, but for reliability it’s dynamic at the local system level. We
include it for our need at a local system level. In the resource adequacy portion and in
PRiSM it is rolled up in the model runs and set aside for capacity from the reliability
model.

Yao Yin: Is the local dynamic done within PRiSM?

James Gall: No, in the reliability model which estimates what the planning margin
should be and then that number gets put into PRiSM. We will talk about that in the next
meeting.

Fred Heutte: The SAAC talked about this in the morning. What is the west going to do
for new resources for the late 2020s and early 2030s with the shape of prices? They are
seeing a similar issue for the regional modeling.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 432 of 1105

James Gall: Yes, that’s the rest of the presentation.

Charlie Inman (Slide 13): How many zones are in Avista’s [Aurora] model?

James Gall: 12 to 14. We are using the same database as the 2020 IRP. There is a newer one, but that one came out too late for this IRP.

Yao Yin (slide 16): Is DR considered on the supply side and not as a load adjustment?

James Gall: It is a load adjustment, but the model dispatches it so it acts like
generation. Included it here because it acts like a generator – same with net metering.

Yao Yin: Net metering is a reduction to load and DR is dispatched?

James Gall: Correct. Model first goes to DR to select the amount of DR. DR is dispatched by the model, but it may or may not be chosen.

Yao Yin: So the amount of DR is from a model result whereas net metering is based on
an entered number?

James Gall: Correct. Along with combined cycle and simple cycle generation. There is
a process to shut off generation – typically renewables have a tax credit and can
operate with a negative price. Hydro has a negative $25 price but it often can’t be
turned off due to a fish constraint. Negative prices are based on dispatch order.

Kathlyn Kinney (slide 22): Is there somewhere where pricing here transfers to price reductions and scenarios where higher priced renewables still fit in and make sense?

James Gall: When the model looks at a resource choice it’s looking at the margin. It is
willing to pay more for the resource that meets those super peak hours. Now you have
to pay for solar plus storage and the extra cost may not equal the extra benefit you get
from that solar plus storage resource. Start to see what hours to dispatch a DR program
and whether they are for economic or for reliability reasons. As far as demand goes, we
are starting to see where some of those resources might be dispatched.

James Gall: Back to slide 21, the history of electric price forecasts since I’ve been
doing them here since 2005. A few times we got it right and others we were too high. In
the teens we were getting lower and now we are pretty close to the market. Prices over
the last 15 years have been falling, similar to loads.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 433 of 1105
James Gall (slide 24): In the analysis, we will make a decision about if a plant is uneconomic, such as Colstrip. In Washington, there is a cost cap for new renewables and it is load versus generation based in other states.

James Gall (slide 25): The rest of the slides are on scenarios that we agreed to
perform previously for this IRP.

Yao Yin: Which natural gas forecast will be used for the October 15th filing [Idaho
avoided cost filing]?

James Gall: Will need to check. We used expected price (middle), which is based on the forecast from the consultants we hire rather than a higher or lower gas price

Yao Yin: Why don’t we include the expected case in here?

James Gall: It is, these are higher and lower scenarios for high and low gas prices.

Jennifer Snyder: Can you give a high level overview of your social cost of carbon
modeling and what’s changed?
James Gall: The model was used to acquire the resources based on the resource plus
cost of the social cost of carbon plus upstream emissions plus construction costs.
Energy efficiency used an average rate, we have been talking about using an
incremental cost (talked about more this afternoon). Market purchases/sales use an
average emission rate as well – this is not a change. Two changes – energy efficiency
average to incremental and including a social cost of carbon cost for resource
acquisition.
Corey Dahl: What is the problem with the social cost of carbon?
James Gall: To capture the cost of carbon associated with the manufacturing and
construction processes associated with the resources – both sides. We used
construction and operations life cycle carbon analysis study from NREL. It is a small
amount of dollars, but it tries to estimate the total carbon costs associated with different
resource choices.
Kathlyn Kinney (slide 31): Incremental means?
James Gall: To run existing infrastructure, how would the system operate in that world.
Jennifer Snyder: I was kicked off the call and just rejoined. I missed what you said and
will have to talk with you later.

James Gall: That’s fine, we can have an offline conversation.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 434 of 1105
2021 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 4 Agenda
Tuesday, November 17, 2020
Virtual Meeting

Topic Time Staff
Introductions 9:00 Lyons

Final Resource Needs Assessment 9:15 Lyons

2020 Renewable RFP Update 9:45 Drake

Break 10:20

Portfolio Modeling Overview 10:30 Gall

Lunch 11:30

Draft PRS and Scenarios 12:30 Gall

Adjourn 2:00
.........................................................................................................................................
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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 435 of 1105
2021 Electric IRP
TAC Introductions and IRP Process Updates
John Lyons, Ph.D.
Fourth Technical Advisory Committee Meeting
November 17, 2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 436 of 1105
Updated TAC Meeting Guidelines
•IRP team working remotely through the rest of this IRP, but still
available by email and phone for questions and comments
•Some processes are taking longer remotely
•Virtual IRP meetings until able to hold large group meetings again
•Joint Avista IRP page for gas and electric:
https://www.myavista.com/about-us/integrated-resource-planning
–TAC presentations
–Documentation for IRP work
–Past IRPs
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 437 of 1105
Virtual TAC Meeting Reminders
•Please mute mics unless speaking or asking a question
•Use the Skype chat box to write questions or comments
or let us know you would like to say something
•Respect the pause
•Please try not to speak over the presenter or a speaker
who is voicing a question or thought
•Remember to state your name before speaking for the
note taker
•This is a public advisory meeting –presentations and
comments will be recorded and documented
3
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 438 of 1105
Integrated Resource Planning
•Required by Idaho and Washington* every other year
•Guides resource strategy over the next twenty + years
•Current and projected load & resource position
•Resource strategies under different future policies
–Resource choices
–Conservation measures and programs
–Transmission and distribution integration for electric
–Gas distribution planning
–Gas and electric market price forecasts
•Scenarios for uncertain future events and issues
•Key dates for modeling and IRP development are
available in the Work Plans
4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 439 of 1105
Technical Advisory Committee
•The public process piece of the IRP –input on what to study, how to
study, and review of assumptions and results
•Wide range of participants involved in all or parts of the process
–Ask questions
–Help with soliciting new members
•Open forum while balancing need to get through all of the topics
•Welcome requests for studies or different assumptions.
–Time or resources may limit the number or type of studies
–Earlier study requests allow us to be more accommodating
–August 1, 2020 was the electric study request deadline
•Planning teams are available by email or phone for questions or
comments between the TAC meetings
5
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 440 of 1105
2021 Electric IRP TAC Schedule
•TAC 1: Thursday, June 18, 2020
•TAC 2: Thursday, August 6, 2020 (Joint with Natural Gas TAC)
•TAC 2.5: Tuesday, August 18, 2020 Economic and Load Forecast
•TAC 3: Tuesday, September 29, 2020
•TAC 4: Tuesday, November 17, 2020
•TAC 4.5: December 2020 –2 Hours on Scenarios
•TAC 5: Thursday, January 21, 2021
•Public Outreach Meeting: February 2021
•TAC agendas, presentations, meeting minutes and IRP files
available at:
https://myavista.com/about-us/integrated-resource-planning
6
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 441 of 1105
Process Updates
Available IRP Data:
•Avista Resource Emissions Summary
•Load Forecast
•CPA Measures
•Avista 2020 Electric CPA –Summary and IRP Inputs
•Home Electrification Conversions
•Named Populations
•Natural Gas Prices
•Social Cost of Carbon
Files Added Since TAC 3:
•High and Low Natural Gas Prices
•Market Modeling Results
•Climate Shift Scenario Inputs
•2021 IRP New Resource Options
7
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 442 of 1105
Today’s TAC Agenda
9:00 Introductions, Lyons
9:15 Final Resource Need Assessment, Lyons
9:45 2020 Renewable RFP Update, Drake
10:20 Break
10:30 Portfolio Modeling Overview, Gall
11:30 Lunch
12:30 Draft PRS and Scenarios, Gall
2:00 Adjourn
8
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 443 of 1105
2020 Electric IRP
Resource Need Assessment
John Lyons, Ph.D.
Fourth Technical Advisory Committee Meeting
November 17, 2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 444 of 1105
Load & Resource Methodology Review
•Sum resource capabilities against loads
•Resource plans are subject to 5% LOLP analysis –
determines planning margins
•Colstrip is included through 2025 per 2020 IRP
•Capacity
–Planning Margin (16% Winter, 7% Summer)
•Using 2020 IRP result; pending future analysis
–Operating Reserves and Regulation (~8%)
–Reduced by planned outages for maintenance
–Plan to largest deficit months between 1-and 18-hour analyses
•Energy
–Reduced by planned and forced outages
–Maximum potential thermal generation over the year
–80-year hydro average, adjusted down to 10th percentile
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 445 of 1105
One Hour Peak Load & Resource Position
3
(700)
(600)
(500)
(400)
(300)
(200)
(100)
0
100
200
300
400
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Me
g
a
w
a
t
t
s
1 Hour Peak Load & Resource Position
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 446 of 1105
18-Hour Peak Load & Resource Position
4
(500)
(400)
(300)
(200)
(100)
0
100
200
300
400
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Me
g
a
w
a
t
t
s
18 Hour Peak Load & Resource Position
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 447 of 1105
Energy Load & Resource Position
5
(700)
(600)
(500)
(400)
(300)
(200)
(100)
0
100
200
300
400
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Me
g
a
w
a
t
t
s
Energy Load & Resource Position
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 448 of 1105
Avista’s Clean Energy Goal
•2027 –100% carbon-neutral
•2045 –100% clean electricity
How we will get there
Goals
•It’s not just about generation –various solutions are necessary
•Maintain focus on reliability and affordability
•Natural gas plays an important part of a clean energy future
•Cost effective technologies need to emerge and mature
6
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 449 of 1105
Washington State Clean Energy Goals
•Energy Independence Act or Initiative 937
–15% of Washington retail load after 2020
–Not modeling for this IRP since CETA takes us beyond 15%
–Last IRP anticipated the inclusion of qualifying BPA and
Wanapum generation, neither of which materialized
•Avista decision to offset costs in lieu of BPA RECs
•Inability to use Wanapum because of difference in hydro methodology
•Clean Energy Transformation Act
–By 2025 –eliminate coal-fired resources from serving WA
customers
–By 2030 –electric supply must be greenhouse gas neutral,
–By 2045 –electric supply must be 100% renewable or be
generated from zero-carbon resources
7
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 450 of 1105
2020 Renewable RFP Update
Chris Drake, Wholesale Marketing Manager
Fourth Technical Advisory Committee Meeting
November 17, 2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 451 of 1105
2
Justification
•Integrated Resource Plan (IRP) -Preferred Resource Strategy (PRS)
•Market indicators suggested competitive pricing for renewables
•Competition for preferred sites
•Corporate renewable goals –systemwide
–Carbon neutral by 2027
–100% clean electricity by 2045
•If bids are not compelling, no obligation to contract
•Capacity Request For Information (or similar investigation) may be considered at a later date
2020 IRP Preferred Resource Strategy
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 452 of 1105
3
Cross-Departmental Review
•Power Supply
–Wholesale marketing, resource
planning, real-time, traders, credit
and resource optimization
•Transmission
•Regulatory
•Insurance/Risk
•Corporate Communications
•Legal
Transmission
Legal
Corporate
Communications
Regulatory
Insurance Risk
Power Supply
2020 Avista
Renewable RFP
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 453 of 1105
4
New Elements of 2020 RFP
•New and existing projects were eligible to bid
–New renewable resources
–Nonemitting electric generation (existing)
•Updated evaluation methodology criteria
–Risk Management, Net Price, Price Risk, Electric Factors, Environmental
–Added Community Impact
•Avista service territory economic impact
•Equity provisions
•Vulnerable and highly impacted communities
•Energy security
•Published evaluation methodology
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 454 of 1105
5
RFP Communications
•Published on
www.myavista.com
•Press Release
–Local media contacts
–GlobeNewswire
distribution to over 600
national outlets
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 455 of 1105
6
Renewable Generation Need
•RFP for up to 300 MW renewables
•2020 IRP’s PRS model
–2022 Montana wind –100 MW
–2022-2023 NW wind –200 MW
•Anticipated proposals –mix of
wind/solar/storage
2020 Avista
Renewable
RFP
Wind
Solar Storage
Repowering
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 456 of 1105
7
Bids Received July 22, 2020
•42 projects
•25 developers
•27 solar (many with battery options)
•13 wind (some with battery option)
•1 hydro
•1 biomass
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 457 of 1105
8
RFP Initial Reactions
•Good selection of shovel ready and existing
projects
•Good geographic distribution
–Projects throughout Northwest with majority in
Washington, then Montana, Idaho and Oregon
•Prices were higher than 2018 RFP
–Sunsetting PTC
–Increased construction costs
•Multiple capacity projects submitted
–Hydro
–Biomass
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 458 of 1105
9
2020 Avista Renewable RFP Evaluation Methodology
General Qualifications
•Compatibility with resource need
•Site control
•Financial plan to bring project to
completion
•Credit requirements
•Procurement plan
•Project completion no later than
December 31, 2023
Evaluation Criteria
•Risk Management -Credit and Developer
Experience
•Net Price -Nominal levelized cost / MWh
•Price Risk -Fixed price, construction, fuel
supply
•Electric Factors -Interconnection,
transmission, technology
•Environmental -Permitting
•Community Impact -Community
involvement, Avista service territory,
vulnerable populations
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 459 of 1105
10
2020 Target Schedule (and Milestones Completed)
June 26, 2020 –RFP Released
July 22, 2020 –Preliminary Information Due
July 31, 2020 –Short-list identified and notified (along with other bidders)
August 21, 2020 –Detailed proposals received from short-list
October 16, 2020 –Final bidder(s) selected for continued review
•December 31, 2020 –Contract negotiation(s)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 460 of 1105
11
2020 RFP Next Steps
•Continue to address specific attributes within proposal(s)
•Contract negotiations with successful project(s)
•Continue internal review to make a final determination
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 461 of 1105
PRiSM Model Overview
James Gall, Electric IRP Manager
Fourth Technical Advisory Committee Meeting
November 17, 2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 462 of 1105
What is PRiSM?
•Preferred Resource Strategy Model
•Mixed Integer Program (MIP) used to select new resources to
meet resource needs of our customers
The user interface
The solver interface
The solver
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 463 of 1105
New PRiSM Features for 2021 IRP
•Significant changes were made to this IRP’s model due to
individual state policies.
–Model purpose: Same as before with additional constraints and options.
–New Constraints: Must meet individual state L&R balance requirements
and clean energy goals.
–New Options: Resources can be added for a specific state or the system.
–New Outputs: State level cost and rate estimates along with resource
strategies.
–Model will be fully available and published on IRP website.
–Model is continually being vetted.
3
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 464 of 1105
Objective Function
Minimize: (WA “Societal” NPV2022-45) + (ID NPV2022-45)
Where:
WA NPV2022-45 = Market Value of Load + Existing & Future Resource Cost/Operating Margin + Social Cost of Carbon + EE TRC
ID NPV2022-45 = Market Value of Load + Existing & Future Resource Cost/Operating Margin + EE UTC
Subject to:
Generation Availability & Timing
Energy Efficiency Potential
Demand Response Potential
Winter Peak Requirements
Summer Peak Requirements
Annual Energy Requirements
Clean Energy Goals
T&D Constraints
Optimization Tolerance: 0.0001 or 1,500 seconds (Note: certain studies longer solution times allowed)
4
Intro to linear programing: https://www.youtube.com/watch?v=Uo6aRV-mbeg
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 465 of 1105
Optimized Cost vs. Actual Costs
•Objective function includes social
costs that are not part of utility
revenue requirement.
•This is used for resource
optimization only.
•Social costs may include:
–Energy Efficiency
•TRC
•Non-energy benefits
•Power Act 10% adder
•T&D Savings
–Social Cost of Carbon
•Actual costs illustrate expected cost
ratepayers will pay.
•Estimate annual revenue
requirements.
•Estimate average rates.
5
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 466 of 1105
Aurora Integration
•Aurora’s price forecast and
resource dispatch are inputs into
PRiSM.
•Each supply resource’s
operations is included by iteration.
–Includes MWh, GHG, Revenue, Fuel
Cost, VOM costs.
•Avista load and existing
contracts are also entered in
totals.
•Energy efficiency load shapes are
marked to market and used for the
energy value of these programs.
•Demand response options are not
modeled in Aurora, but use hourly
price results for a market value.
6
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 467 of 1105
Thermal Resources
•Model may retain or exclude specific resources in any year.
–Retirements are for both states (except Colstrip).
–No re-allocation of existing resources between states.
•Includes major future capital spend for continued operation along with O&M costs.
•Resource costs and benefits are allocated using PT ratio (65% WA, 35% ID).
•Lancaster PPA expires in October 2026.
•Northeast assumes retirement in 2035 & Boulder Park in 2040.
•Kettle Falls CT is excluded from retirement option, but is excluded from winter peak
due to pending pipeline review.
•Colstrip must be removed in Washington by 2025.
–Model can remove earlier or retain for Idaho.
–Washington’s share of cost after 2025 are not included in model.
7
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 468 of 1105
Hydro Resources
•Available for full length of study.
•Post Falls assumes rebuild in 2025 (found cost effective in 2021 IRP).
•Energy, capacity, and clean energy attributes split between states using PT ratio
(65% WA/35% ID).
8
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 469 of 1105
Other Existing “Resources”
•PURPA
–CETA has provision for in-state PURPA generation reducing clean energy obligation.
–For modelling purposes, generation is allocated to each state it qualifies under PURPA.
•Other Wholesale Contracts
–Current PPAs are allocated to each state using PT ratio.
–Except for Adam’s Neilson Solar-fully allocated to Washington.
–PURPA related resales are fully allocated to state it qualifies for under PURPA
•Renewable Energy Credits (RECs)
–Each state receives “RECs” from its “PT ratio” share of resources.
–Model allows for sale of RECs between states subject to limits.
9
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 470 of 1105
Energy Efficiency
Washington
•AEG provides EE potential by year and program
–Winter peak savings
–Summer peak savings
–Annual average savings
•Electrical savings are grossed up for T&D losses
•Benefit of T&D Capital Avoidance ($25.35 per kW-yr)
•Total Resource Cost (TRC) test
•Add value for non-energy benefits ($23 per MWh)
•Power Act 10% adder for energy and capacity value
•Social Cost of Carbon using regional incremental
emission rates per MWh
•Included in L&R constraints to avoid new supply
resource options
Idaho
•AEG provides EE potential by year and program
–Winter peak savings
–Summer peak savings
–Annual average savings
•Electrical savings are grossed up for T&D losses
•Benefit of T&D Capital Avoidance ($25.35 per kW-yr)
•Utility Cost Test (UCT) for cost effectiveness
•Included in L&R constraints to avoid new supply
resource options
10
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 471 of 1105
Demand Response
•Programs available in each state determined by AEG.
•AEG estimated capital amortized over 5 years and a levelized cost is created by combining
the O&M costs.
•Projects must ramp in over time (except large industrial).
–25 MW of industrial DR for Washington
•Water heating is different between states:
–WA includes CTA-2045
–DLC water heating in ID
•Energy arbitrage and savings is included based on 50% of potential use.
–10% preference adder included for Washington.
•Peak Credit is using 2020 IRP estimate of 60%.
–Additional studies may be available to validate.
–Based on prior IRP-this estimate could be too high.
11
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 472 of 1105
Supply-Side Options
•Uses levelized fixed and variable costs for potentially owned resources (i.e.
natural gas, storage).
•Uses PPA $/MWh or $/kW-yr costs for resources.
•All generation costs are available on the IRP website.
•Washington PPA options includes rate of return for clean resources.
•Resources must be added in increments of probable size of actual
acquisition-not any value-this assumption can increase cost or change
resource strategy.
12
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 473 of 1105
Clean Energy Goals
•Washington
–100% clean energy (carbon neutral) by 2030
–100% clean energy by 2045
•MAJOR ASSUMPTIONS:
–By 2030, Washington’s clean energy must equal
100% of net retail sales; 20% of this total may
come from RECs.
•Only REC purchases assumed are from Idaho
customers at $7.50/MWh escalating
–2045, 100% goal of all 100% of electrons clean is
not modeled at this time (likely 2024 IRP).
–Between 2030 and 2045 REC transfers decline
to zero.
–Prior to 2030 REC transfers are limited to non-
hydro resources to encourage early acquisition.
•Idaho
–No clean energy requirement.
–Idaho is allowed to sell REC’s to Washington
LSE.
–Other REC sales to other parties are not
modeled.
–Scenarios will show cost of additional renewable
energy acquisition.
13
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 474 of 1105
Greenhouse Gas Emissions
•The model estimates the GHG emissions for thermal resource
dispatch.
–Market purchase/sale effects are estimated using the regional average
emission rate.
–Storage resources include a market based GHG adder.
•Societal emissions saved from Energy Efficiency using an incremental
emissions approach are estimated.
•Includes upstream emissions for natural gas resources.
•Construction and operation emissions are included.
14
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 475 of 1105
Social Cost of Carbon or Social Cost of Greenhouse Gas
Washington
–Costs are included for resource dispatch of
new thermal & storage options.
–Cost are also included for existing natural
gas-fired resources.
–Energy Efficiency receives a social credit
for emission savings.
–No cost are included for market
transactions, except for storage resources.
•This would give extra incentive to
renewables by valuing the social cost of
carbon on non-Avista resources. [Potential
scenario]
•Model time step doesn’t allow for SCC on
purchases only.
Idaho
–No direct cost of GHG is included.
–Objective function is 65% Washington Cost-
therefore existing resources are influenced
by this cost and could have effects on
Idaho.
–A scenario using the Washington
methodology will be studied.
15
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 476 of 1105
Transmission
•Resources have either a capital investment or a wheeling charge.
–Capital investments are based on the transmission cost estimates from the September 2020 TAC 3
meeting.
•Resource options in the Rathdrum, Idaho area are a challenge.
–Approximately 100 MW can be added without significant investment.
–Over 100 MW may either require additional infrastructure or Remedial Action Scheme (RAS).
•RAS has not been studied
–Avista has resource options in the area without new transmission (i.e. Lancaster), but if Lancaster
operates and Avista builds new resources would require an investment or RAS.
–For this analysis no additional Rathdrum transmission is assumed until either Lancaster is ruled out
from an RFP or RAS is determined to not be an option.
•By including the additional transmission cost could either create a portfolio where Idaho must pursue a more costly option-
an RFP needs to decide this rather then an IRP without cost of a Lancaster extension.
16
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 477 of 1105
Resource Adequacy Check
•To the furthest extent possible, portfolios will be studied for resource
adequacy for 2025, 2030, and 2040.
–Each study takes 3 days to complete; Avista has only 2 machines capable of this work.
•If a portfolio fails the adequacy test-additional capacity will be required or
noted.
•Avista does not expect to complete all studies for the draft IRP release.
–Although studies will be conducted through February for the final draft portfolios requiring
this work.
–All other studies will need to rely on the planning margin for its resource adequacy test.
•Reliability data input files are still in process and results are not available at
this time.
17
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 478 of 1105
Equity Provisions
•Avista previously identified potential areas within its system qualifying for
VP/HIC status, although final determination is still ongoing.
•A baseline analysis for cost and reliability/resilience has been completed.
•Avista is developing an Equity Advisory Group (EAG).
–EAG will determine final VP/HIC determinants.
–Develop outreach plan for each community to understand energy needs and preferences.
–Study solutions and develop programs to meet needs of the communities.
•Process to develop a solid plan for these VP/HIC communities will not be
available for this IRP.
18
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 479 of 1105
Least “Reasonable” Cost Strategy & Baseline Analysis
“Not Preferred Resource Strategy Yet”
James Gall, Electric IRP Manager
Fourth Technical Advisory Committee Meeting
November 17, 2020
DRAFT
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 480 of 1105
Safe Harbor Statement
This document contains forward-looking statements. Such statements are subject to a variety of risks,
uncertainties and other factors,most of which are beyond the Company’s control, and many of which could
have a significant impact on the Company’s operations, results of operations and financial condition, and
could cause actual results to differ materially from those anticipated.
For a further discussion of these factors and other important factors,please refer to the Company’s reports
filed with the Securities and Exchange Commission.The forward-looking statements contained in this
document speak only as of the date hereof.The Company undertakes no obligation to update any forward-
looking statement or statements to reflect events or circumstances that occur after the date on which such
statement is made or to reflect the occurrence of unanticipated events.New risks,uncertainties and other
factors emerge from time to time, and it is not possible for management to predict all of such factors,nor
can it assess the impact of each such factor on the Company’s business or the extent to which any such
factor, or combination of factors, may cause actual results to differ materially from those contained in any
forward-looking statement.
DRAFT
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 481 of 1105
Other Caveats
•Clean Energy Transformation Act (CETA) rules and requirements are not complete.
–This is Avista’s best estimate of known requirements.
•Avista is negotiating with the renewable Request for Proposals (RFP) shortlist bidders
–This may change the results of the resource plan due to a potential contract.
•IRP resource options are primarily “new” resource options-RFP will determine whether or
not existing resources can be acquired at similar or lower cost than “new” options.
•Avista may not be able to physically retire or exit certain resources as the IRP PRiSM model
determines.
•No future state specific resource cost allocation agreement has been made.
•Forward looking rates include non-modeled power supply cost escalating at 2% per year-
–DO NOT TAKE THIS AS A RATE FORECAST
–This is for informational purposes only
DRAFT
3
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 482 of 1105
Energy Efficiency Results
-
100.0
200.0
300.0
400.0
500.0
600.0
700.0
800.0
900.0
1,000.0
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
GW
h
Washington Energy
2020 IRP
2021 IRP
-
20.0
40.0
60.0
80.0
100.0
120.0
140.0
160.0
180.0
200.0
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
MW
Washington Summer Peak
2020 IRP
2021 IRP
-
20.0
40.0
60.0
80.0
100.0
120.0
140.0
160.0
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
MW
Washington Winter Peak
2020 IRP
2021 IRP
-
100.0
200.0
300.0
400.0
500.0
600.0
700.0
800.0
900.0
1,000.0
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
GW
h
Idaho Energy
2020 IRP
2021 IRP
-
20.0
40.0
60.0
80.0
100.0
120.0
140.0
160.0
180.0
200.0
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
MW
Idaho Summer Peak
2020 IRP
2021 IRP
-
20.0
40.0
60.0
80.0
100.0
120.0
140.0
160.0
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
MW
Idaho Winter Peak
2020 IRP
2021 IRP
NOTE:
Energy Efficiency results
do not materially impact
supply resource strategy.
Supply resource strategy
is based on the load
forecast for both energy
and peak.
EE is first estimated, then
added to the load
forecast; the model then
picks economic EE to
have net load equal to the
load forecast
DRAFT
4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 483 of 1105
Cumulative Energy Efficiency End Use Results (GWh)
Appliances 0.7 0.1 6.6 0.8 15.6 2.7
Cooling 6.4 0.5 41.7 2.8 61.2 7.0
Electronics 1.1 0.2 15.2 4.8 27.1 9.3
Exterior Lighting 4.3 1.4 24.8 7.8 37.2 14.3
Food Preparation 0.1 0.0 2.2 0.4 5.9 0.9
Interior Lighting 21.1 13.0 103.6 49.3 176.3 89.6
Miscellaneous 1.5 0.3 16.0 2.8 36.0 5.5
Motors 4.9 3.4 35.3 24.0 41.3 27.0
Office Equipment 0.6 0.0 3.6 0.0 6.2 0.0
Process 0.7 0.1 4.1 1.1 4.5 1.4
Refrigeration 8.3 0.3 60.9 2.3 70.0 2.6
Space Heating 13.1 3.5 122.9 30.3 175.4 39.9
Ventilation 5.3 0.7 31.0 5.2 46.1 12.5
Water Heating 4.6 1.4 65.9 8.3 120.6 9.7
Total 72.7 25.1 533.7 140.0 823.4 222.3
DRAFT
5
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 484 of 1105
Cumulative Energy Efficiency Segment Results (GWh)
DRAFT
6
WA ID WA ID WA ID
College 2.7 0.7 13.8 4.2 19.5 7.5
Grocery 6.8 0.2 47.6 1.4 56.6 1.7
Health 2.7 0.9 14.5 4.7 23.0 8.1
Industrial 12.0 7.9 62.5 41.1 91.4 61.1
Large Office 6.6 1.3 43.6 8.8 67.5 16.5
Lodging 1.4 0.6 8.9 2.9 13.2 4.9
Low Income 3.4 1.7 40.4 10.7 60.8 13.2
Miscellaneous 6.1 1.9 41.5 10.7 61.3 19.1
Mobile Home 0.7 0.2 7.2 1.4 14.2 2.1
Multi-Family 0.5 0.2 7.6 1.2 16.6 1.9
Restaurant 2.1 0.2 15.1 1.6 20.2 2.3
Retail 5.6 2.0 35.8 10.3 52.8 17.9
School 3.1 0.1 18.5 0.4 28.7 0.8
Single Family 14.4 5.1 147.6 28.6 250.3 42.8
Small Office 2.4 1.1 16.9 7.4 26.5 13.5
Warehouse 2.4 0.9 12.4 4.7 20.8 8.9
Total 72.7 25.1 533.7 140.0 823.4 222.3
2023 2031 2045
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 485 of 1105
Higher Washington Energy Efficiency Goals
More Aggressive Ramp Rates & Higher Avoided Costs
33
73
117
168
226
288
353
417
478
534
107
0
100
200
300
400
500
600
Cumulative Savings
Pro Rata 10
CPA Pro-Rata Share 106,740 72,338
Distribution and Street Light Efficiency 219 504
EIA Target 106,959 72,842
Decoupling Threshold 5,348 3,642
Total Utility Conservation Goal 112,307 76,484
Excluded Programs (NEEA)-14,016 -14,016
Utility Specific Conservation Goal 98,291 62,468
Decoupling Threshold -5,348 -3,642
EIA Penalty Threshold 92,943 58,826
DRAFT
7
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 486 of 1105
Stacked 20-Year Levelized Energy Efficiency
Avoided Cost (WA)
DRAFT
8
$0
$20
$40
$60
$80
$100
$120
$140
Le
v
e
l
i
z
e
d

2
0
y
r

$
/
M
W
h
Energy Value
$0
$20
$40
$60
$80
$100
$120
Le
v
e
l
i
z
e
d

2
0
y
r

$
/
k
W
-yr
Capacity Value
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 487 of 1105
Stacked 20-Year Levelized Energy Efficiency
Avoided Cost (ID)
DRAFT
9
$0
$20
$40
$60
$80
$100
$120
$140
Le
v
e
l
i
z
e
d

2
0
y
r

$
/
M
W
h
Energy Value
$0
$20
$40
$60
$80
$100
$120
Le
v
e
l
i
z
e
d

2
0
y
r

$
/
k
W
-yr
Capacity Value
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 488 of 1105
Demand Response
Program Washington Idaho
Time of Use Rates 2 MW (2024)2 MW (2030)
Variable Peak Pricing 7 MW (2024)6 MW (2030)
Large C&I Program 25 MW (2027)n/a
DLC Smart Thermostats 7 MW (2030)n/a
Third Party Contracts 15 MW (2031)n/a
Behavioral Programs 1 MW (2039)n/a
Total 56 MW 8 MW
Note: DR programs in another state for the benefit of the other state is not modeled
DRAFT
10
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 489 of 1105
2022-2025 Supply Side Resource Changes
2022: Economic to exit out of Colstrip 3 & 4 (Both)
2023: 100 MW of Montana Wind (WA)
2024: 50 MW of Montana Wind (WA)
2025: No Action
NOTE: Renewable RFP may change this strategy
DRAFT
11
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 490 of 1105
2026-2029 Supply Side Resource Changes
2026: 50 MW Montana Wind (WA)
48 MW NG SCCT (Both)
Lancaster CCCT contract ends (Both)
2026/27: 84 MW NG SCCT (ID)
84 MW NG SCCT (Both)
12 MW Upgrade Kettle Falls (Both)
2028: 50 MW Montana Wind (WA)
2029: 50 MW Solar + 50 MW 4-Hour Storage (Both)
NOTE: Renewable RFP may change this strategy
DRAFT
12
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 491 of 1105
2030-2033 Supply Side Resource Changes
2030:No Action
2031:75 MW Hydro Contract Renewal (WA)
2032:No Action
2033:No Action
NOTE: Renewable RFP may change this strategy
DRAFT
13
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 492 of 1105
2034-2037 Supply Side Resource Changes
2034:5 MW Rathdrum CT Upgrade (Both)
2035:50 MW Solar + 50 MW 4-Hour Storage (Both)
Northeast Retires (Both)
2036:50 MW Hydrogen SCCT (WA)
55 MW NG SCCT (ID)
2037:No Action
DRAFT
14
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 493 of 1105
2038-2045 Supply Side Resource Changes
2038:50 MW Montana Wind (WA)
2039: No Action
2040: 50 MW Solar + 50 MW 4-Hour Storage (Both)
2041: 50 MW Solar + 50 MW 4-Hour Storage (WA)
50 MW Montana Wind (WA)
Boulder Park Retires (Both)
2042:50 MW Montana Wind (WA)
50 MW Solar + 50 MW 4-Hour Storage (Both)
2043:50 MW Solar (WA)
100 MW Solar + 100 MW 4-Hour Storage (Both)
2044:50 MW Solar + 50 MW 4-Hour Storage (ID)
2045:150 MW Solar (WA)
30 MW Storage (ID)
DRAFT
15
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 494 of 1105
Least Reasonable Cost Resource Selection (MW)
NG CT 0 0 0 0 48 84 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Solar 0 0 0 0 0 0 0 50 0 0 0 0 0 50 0 0 0 0 50 0 50 100 0 0
Storage Added to Solar 0 0 0 0 0 0 0 50 0 0 0 0 0 50 0 0 0 0 50 0 50 100 0 0
Wind 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Storage 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Hydrogen 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Other- (Clean Capacity)0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Thermal Upgrade 0 0 0 0 0 12 0 0 0 0 0 0 5 0 0 0 0 0 0 0 0 0 0 0
Hydro 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Washington
NG CT 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Solar 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 50 0 50 0 150
Storage Added to Solar 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 50 0 0 0 0
Wind 0 100 50 0 50 0 50 0 0 0 0 0 0 0 0 0 50 0 0 50 50 0 0 0Storage0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Hydrogen 0 0 0 0 0 0 0 0 0 0 0 0 0 0 50 0 0 0 0 0 0 0 0 0
Other- (Clean Capacity)0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Thermal Upgrade 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Hydro 0 0 0 0 0 0 0 0 0 75 0 0 0 0 0 0 0 0 0 0 0 0 0 0
DR Capability 0 0 1 4 9 37 37 37 38 42 47 54 56 56 56 56 56 56 56 57 57 56 56 56EE- Winter Capacity 3 4 5 6 7 7 8 8 7 6 5 4 4 3 2 2 2 1 1 1 1 0 0 0
EE- Summer Capacity 5 5 6 7 8 8 9 8 8 7 6 5 4 3 3 2 2 2 2 0 0 0 0 0
Idaho
NG CT 0 0 0 0 0 84 0 0 0 0 0 0 0 0 55 0 0 0 0 0 0 0 0 0
Solar 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 50 0Storage Added to Solar 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 50 0
Wind 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Storage 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 30
Hydrogen 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Other- (Clean Capacity)0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Thermal Upgrade 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0Hydro0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
DR Capability 0 0 0 0 0 0 0 0 1 3 7 9 10 10 10 10 9 9 9 9 9 9 9 8
EE- Winter Capacity 1 1 2 2 2 2 2 2 2 2 1 1 1 0 0 0 0 0 0 0 0 0 0 0
EE- Summer Capacity 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 0 0 0 0 0 0 0 0 0
DRAFT
16 Note: DR is cumulative due to the small changes year to year
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 495 of 1105
Clean Energy Share (aMW)
-
200
400
600
800
1,000
1,200
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
System
Existing Clean Resources RECs New Clean Resources Net Sales
-
200
400
600
800
1,000
1,200
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Washington
Existing Clean Resources RECs New Clean Resources Net Sales
-
200
400
600
800
1,000
1,200
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Idaho
Existing Clean Resources RECs New Clean Resources Net Sales
System Clean Resource Percentage
2022: 74.8%
2027: 78.3%
2045: 85.5%
Excludes Clean Market Purchases
DRAFT
17
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 496 of 1105
Annual Average Least Reasonable Cost Rate Forecast
NOTE: Estimated rates only using 2% annual rate increase for non-modeled costs
DRAFT
18
0.00
0.02
0.04
0.06
0.08
0.10
0.12
0.14
0.16
0.18
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Do
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K
W
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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 497 of 1105
Greenhouse Gas Forecast
Note: Assumes Colstrip exits the portfolio
DRAFT
19
Mi
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M
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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 498 of 1105
Baseline Analysis
1.Least Reasonable Cost Strategy: Includes all requirements
2.Baseline Portfolio 1: Excludes CETA’s 2030 and 2045 goals
–Used for incremental cost calculation
3.Baseline Portfolio 2: Baseline Portfolio 1 + removal of SCC
–Energy Efficiency held constant from LCS
–Used to estimate cost of capacity by comparing to Baseline 3
4.Baseline Portfolio 3: Baseline Portfolio 2 + removal of capacity
constraints
–Estimates cost to serve load without new resources
DRAFT
20
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 499 of 1105
Resource
Mix
Summary
DRAFT
21
1. LRCS 2. Baseline 1 3. Baseline 2 4. Baseline 3
Shared System Resource
NG CT 132 132 479 0
Solar 300 150 150 0
Storage Added to Solar 300 150 150 0
Wind 0 0 0 0
Storage 0 33 0 0
Hydrogen 0 0 0 0
Other- (Clean Capacity)0 0 0 0
Thermal Upgrade 17 17 17 0
Hydro 0 0 75 0
Washington
NG CT 0 84 0 0
Solar 250 0 0 0
Storage Added to Solar 50 0 0 0
Wind 400 0 0 0
Storage 0 30 0 0
Hydrogen 50 100 0 0
Other- (Clean Capacity)0 0 0 0
Thermal Upgrade 0 0 0 0
Hydro 75 75 0 0
DR Capability 56 55 35 3
EE- Winter Capacity 88 86 88 88
EE- Summer Capacity 101 94 101 101
Idaho
NG CT 139 139 0 0
Solar 50 0 50 0
Storage Added to Solar 50 0 50 0
Wind 0 0 0 0
Storage 30 90 80 0
Hydrogen 0 0 0 0
Other- (Clean Capacity)0 0 0 0
Thermal Upgrade 0 0 0 0
Hydro 0 0 0 0
DR Capability 8 19 19 2
EE- Winter Capacity 24 23 24 24
EE- Summer Capacity 13 13 13 13
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 500 of 1105
Cost Comparison of Baseline Scenarios
Cost difference is cost of clean energy targets
Cost difference is cost of
clean energy targets & SCC
(excludes EE)Cost difference is cost of
capacity
DRAFT
22
Le
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e
d

R
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t
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 501 of 1105
Washington CETA Cost Cap Analysis
(assumes current methodology)
Washington Incremental Cost Calculation 2022 2023 2024 2025
Revenue Requirement w/ SCC 651 669 693 698
Baseline (Total Revenue Requirement Plus SCC)649 657 670 675
Annual Delta 2 12 23 23
Percent Change 0% 2% 3% 3%
Four Year Max Spending 118.4
Annual Max Spending 29.6 29.6 29.6 29.6
Forecasted Spend 59
(59)
Washington Incremental Cost Calculation 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
Revenue Requirement w/ SCC 718 715 735 749 763 775 782 797 810 825 855 861 889 900 914 925 951 984 1,013 1,030
Baseline (Total Revenue Requirement Plus SCC)685 702 713 725 735 754 759 775 786 798 829 834 868 877 887 888 912 936 986 996
Annual Delta 33 13 22 23 28 22 23 22 24 28 25 27 21 23 27 37 39 48 27 34
Percent Change 5% 2% 3% 3% 4% 3% 3% 3% 3% 3% 3% 3% 2% 3% 3% 4% 4% 5% 3% 3%
Four Year Max Spending 127.9 136.8 146.0 158.5 113.2
Annual Max Spending 32.0 32.0 32.0 32.0 34.2 34.2 34.2 34.2 36.5 36.5 36.5 36.5 39.6 39.6 39.6 39.6 37.7 37.7 37.7
Forecasted Spend 91 94 104 108 113
(37) (43) (42) (50) 0
Incremental cost
Annual spending to use cap
Forecasted to be under cap
Avista should hit 2042-44 rate
cap. Increases exceed 2% each year over
baseline, but rate cap is exponential.
DRAFT
23
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 502 of 1105
New Supply-Side Resource Avoided Costs
DRAFT
24
Year
Flat
($/MWh)
On-Peak
($/MWh)
Off-Peak
($/MWh)
Clean
Energy
Premium
($/MWh)
Capacity
Premium
($/kW-Yr)
20 yr Levelized $25.86 $25.18 $26.78 $25.27 $57.64
24 yr Levelized $27.18 $26.36 $28.30 $25.33 $62.15
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 503 of 1105
Least “Reasonable” Cost Strategy & Baseline Analysis
“Not Preferred Resource Strategy Yet”
James Gall, Electric IRP Manager
Fourth Technical Advisory Committee Meeting
November 17, 2020
DRAFT
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 504 of 1105
Safe Harbor Statement
This document contains forward-looking statements. Such statements are subject to a variety of risks,
uncertainties and other factors,most of which are beyond the Company’s control, and many of which could
have a significant impact on the Company’s operations, results of operations and financial condition, and
could cause actual results to differ materially from those anticipated.
For a further discussion of these factors and other important factors,please refer to the Company’s reports
filed with the Securities and Exchange Commission.The forward-looking statements contained in this
document speak only as of the date hereof.The Company undertakes no obligation to update any forward-
looking statement or statements to reflect events or circumstances that occur after the date on which such
statement is made or to reflect the occurrence of unanticipated events.New risks,uncertainties and other
factors emerge from time to time, and it is not possible for management to predict all of such factors,nor
can it assess the impact of each such factor on the Company’s business or the extent to which any such
factor, or combination of factors, may cause actual results to differ materially from those contained in any
forward-looking statement.
DRAFT
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 505 of 1105
Portfolio Scenarios-2021 IRP
1.Preferred Resource Strategy
2.Baseline Portfolio 1 (No CETA renewable targets)
3.Baseline Portfolio 2 (No CETA renewable targets/SCC)
4.Baseline Portfolio 3 (No additions)
5.Clean Resource Plan (100% Portfolio net clean by 2027)
6.Clean Resource Plan (100% Portfolio clean by 2045)
7.Social Cost of Carbon applied to Idaho
8.Least Cost Plan-w/ low load growth
9.Least Cost Plan-w/ high load growth
10.Least Cost Plan-w/ Northwest Resource Adequacy Market Peak Credits
11.Heating Electrification Scenario 1
12.Heating Electrification Scenario 2
13.Heating Electrification Scenario 3
14.Least Cost Plan-w/ climate shift
15.Least Cost Plan-w/ 2x SCC prices
16.Colstrip serves Idaho customers through 2025
17.Colstrip serves Idaho customers through 2035
18.Colstrip serves Idaho customers through 2045
19.If necessary: CETA deliver to customers each hour
20.Social Cost of Carbon “Tax” Least Cost Strategy
21.If necessary: other resource specific scenarios depending on outcome of PRS results
Only black font
scenarios are shown
in this presentation
DRAFT
3
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 506 of 1105
Scenario Descriptions
1.Least Reasonable Cost Strategy: Includes all requirements
2.Baseline Portfolio 1: Excludes CETA’s 2030 and 2045 goals
–Used for incremental cost calculation
3.Baseline Portfolio 2: Baseline Portfolio 1 + removal of SCC
–Energy Efficiency held constant from LCS
4.Baseline Portfolio 3: Baseline Portfolio 2 + removal of capacity constraints
–Energy Efficiency held constant from LCS
5.Clean Resource Plan (2027)
–Add constraint to meet or exceed 100% of all retail sales with clean energy
6.Clean Resource Plan (2045)
–Add constraint to meet or exceed 100% of all retail sales with clean energy
–All thermal resources must exit by 2044
–No new thermal resources
7.Social Cost of Carbon applied to Idaho
–Includes SCC as cost adder to generation and savings for EE using same method as
Washington State
DRAFT
4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 507 of 1105
Scenario Descriptions Continued
15.Least Cost Plan-with 2 time SCC prices
–Double of Social Cost of Carbon charge for Washington Only
16.Colstrip serves Idaho customers through 2025
–Colstrip obligated to run through 2025 in both states
17.Colstrip serves Idaho customers through 2035
–Colstrip obligated to run though 2035 for Idaho
18.Colstrip serves Idaho customers through 2045
–Colstrip obligated to run through 2045 for Idaho
DRAFT
5
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 508 of 1105
Portfolio Sensitivities
•Portfolio scenarios will be tested with alternative price forecasts
–High Natural Gas Prices
–Low Natural Gas Prices
–Social Cost of Carbon “Tax”
–Climate Shift
•Likely available for draft document, but not TAC presentations
DRAFT
6
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 509 of 1105
Scenario Cumulative Resource Selection
NG CT 132 132 479 0 0 0 48 0 132 132 132
Solar 300 150 150 0 650 670 200 100 300 300 300
Storage Added to Solar 300 150 150 0 650 625 200 100 300 300 300
Wind 0 0 0 0 250 550 0 0 0 0 0
Storage 0 33 0 0 0 0 0 0 0 0 0
Hydrogen 0 0 0 0 0 0 0 0 0 0 0
Other- (Clean Capacity)0 0 0 0 0 20 0 0 0 0 0
Thermal Upgrade 17 17 17 0 17 12 17 17 17 17 17
Hydro 0 0 75 0 0 0 75 0 0 0 0
Washington
NG CT 0 84 0 0 48 0 84 144 0 0 0
Solar 250 0 0 0 100 0 350 0 250 250 250
Storage Added to Solar 50 0 0 0 0 0 50 0 75 0 0
Wind 400 0 0 0 200 450 400 600 400 400 400
Storage 0 30 0 0 0 250 0 140 0 10 10
Hydrogen 50 100 0 0 50 100 50 100 50 50 50
Other- (Clean Capacity)0 0 0 0 0 50 0 0 0 0 0
Thermal Upgrade 0 0 0 0 0 0 0 0 0 0 0
Hydro 75 75 0 0 75 75 0 75 75 75 75
DR Capability 56 55 35 3 56 104 56 55 55 57 57
EE- Winter Capacity 88 86 88 88 89 91 90 98 88 91 92
EE- Summer Capacity 101 94 101 101 99 115 116 142 113 100 100
Idaho
NG CT 139 139 0 0 120 0 84 223 139 139 55
Solar 50 0 50 0 300 585 0 0 0 0 50
Storage Added to Solar 50 0 50 0 125 200 0 0 0 0 50
Wind 0 0 0 0 150 50 0 0 0 0 0
Storage 30 90 80 0 0 0 40 50 90 70 130
Hydrogen 0 0 0 0 0 250 50 50 0 0 0
Other- (Clean Capacity)0 0 0 0 0 0 0 0 0 0 0
Thermal Upgrade 0 0 0 0 0 0 0 0 0 0 0
Hydro 0 0 0 0 0 0 0 0 0 0 0
DR Capability 8 19 19 2 19 19 21 7 8 17 20
EE- Winter Capacity 24 23 24 24 25 33 39 23 22 21 23
EE- Summer Capacity 13 13 13 13 18 22 36 12 15 11 15
DRAFT
7
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 510 of 1105
Existing Resource “Exits”
1- LRCS
2- Baseline
1
3- Baseline
2
4- Baseline
3 w/ EE
5- Clean
Resource
Plan (2027)
6- Clean
Resource
Strategy
(2045)
7- SCC
Idaho 15- 2x SCC
16- Colstrip
2025
17- Colstrip
2035
18- Colstrip
2045
Coyote Springs 2 - - - - -2044 -2022 - - -
Lancaster 2026 2026 2026 2026 2026 2026 2026 2026 2026 2026 2026
Colstrip (3)2021 2021 2021 2021 2021 2035 2021 -2025 2035 2045
Colstrip (4)2021 2021 2021 2021 2021 2021 2021 2025 2025 2035 2045
Kettle Falls - - - - - - - - - - -
Kettle Falls CT - - - - -2044 - - - - -
Boulder Park 1-6 2040 2037 2026 2040 2040 2040 2040 2030 2040 2040 2040
Rathdrum 1 - - - - -2044 - - - - -
Rathdrum 2 - - - - -2044 - - - - -
Northeast A&B 2035 2035 2026 2035 2035 2035 2035 2035 2035 2035 2035
Note:
Assumes each plant is available through December 31st of the final year;
Exception: Lancaster PPA expires Oct 2026.
Dash indicates no plant exit in the study
DRAFT
8
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 511 of 1105
2022-45 Levelized Revenue Requirement
$730 $705 $702 $681
$736 $748 $732
$778
$732 $733 $733
$380 $384 $381 $368
$410 $411 $381 $393 $393 $381 $381
$0
$100
$200
$300
$400
$500
$600
$700
$800
$900
1- LRCS 2- Baseline
1
3- Baseline
2
4- Baseline
3
5- CRS
(2027)
6- CRS
(2045)
7- LRCS
(ID SCC)
15- LRCS
2x SCC
16- Colstrip
2025
17- Colstrip
2035
18- Colstrip
2045
Washington Idaho
DRAFT
9
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 512 of 1105
Rate Estimates (Average Annual)
WA-2030 ID- 2030 WA- 2045 ID- 2045
DRAFT
10
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 513 of 1105
Annual Greenhouse Gas Emission
Avista Dispatch & Storage Purchases
DRAFT
11
Mi
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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 514 of 1105
Cost vs. GHG Tradeoffs
Change in Levelized Cost vs. Change in Levelized Net Emissions
1-LRCS
2-Baseline 1
3-Baseline 2
4-Baseline 3
5-CRS (2027)
6-CRS (2045)
7-SCC Idaho
15-LRCS 2x SCC
16-Colstrip 2025
17-Colstrip 2035
18-Colstrip 2045
DRAFT
12
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 515 of 1105
2030 Risk Analysis
Measures 2030 standard deviation of “modeled” power cost compared to levelized cost
DRAFT
13
$0
$10
$20
$30
$40
$50
$60
$1,040 $1,060 $1,080 $1,100 $1,120 $1,140 $1,160 $1,180
20
3
0

S
t
d
e
v

(
m
i
l
l
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n
s
)
2022-2044 Levelized Revenue Requirement (Millions)
Note: PPA cost are considered “fixed” for this analysis-meaning the cost do not change with changes in delivered energy
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 516 of 1105
2045 Risk Analysis
Measures 2045 standard deviation of “modeled” power cost compared to levelized cost
DRAFT
14 Note: PPA cost are considered “fixed” for this analysis-meaning the cost do not change with changes in delivered energy
$0
$20
$40
$60
$80
$100
$120
$140
$160
$1,040 $1,060 $1,080 $1,100 $1,120 $1,140 $1,160 $1,180
20
4
5

S
t
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v

(
m
i
l
l
i
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n
s
)
2022-2044 Levelized Revenue Requirement (Millions)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 517 of 1105
2045 Upper Tail Risk Analysis
95th percentile power cost minus mean power cost compared to levelized cost
DRAFT
15 Note: PPA cost are considered “fixed” for this analysis-meaning the cost do not change with changes in delivered energy
$0
$50
$100
$150
$200
$250
$300
$1,040 $1,060 $1,080 $1,100 $1,120 $1,140 $1,160 $1,180
20
4
5

T
a
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l

R
i
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k

(
m
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s
)
2022-2044 Levelized Revenue Requirement (Millions)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 518 of 1105
Next Steps
•Post PRiSM model to website
•Complete other scenarios and sensitivities
•Begin reliability studies
•Update PRiSM model for any modifications
•Select Preferred Resource Strategy
•Re-run scenarios and sensitivities
•Continue reliability studies if necessary
16
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 519 of 1105
2021 Electric IRP TAC 4 Meeting – November 17, 2020
Annette Brandon, James Gall, Lori Hermanson, John Lyons, Tom Pardee, Chip Estes,
Dainee Gibson-Webb (ICL), Dean Kinzer, Jody Morehouse, Kevin Keyt, Annie Gannon,
Leona Haley, Clint Kalich, Melissa Kuo (Clearwater), Michael Eldred (IPUC), Mike Louis
(IPUC), Rachel Farnsworth (IPUC), Peter Sawicki (Mitsubishi Power), Jennifer Snyder
(UTC), Terri Carlock (IPUC), Jan Himebaugh (BIAW), Shay Bauman (PC), Joanna
Huang (UTC), Ryan Finesilver, Marissa Warren, Jaime Majure, James McDougal, Joni
Bosh (NWEC) , Amanda Ghering, George Lynch, Katie Ware, Ian McGetrick, John
Chatburn, Amy Wheeless (NWEC), Corey Dahl (Public Counsel), Jorgen Rasmussen,
Jared Hansen, Garrett Brown, Pat Ehrbar, Charlie Inman (PSE), Steve Johnson (UTC),
Terrance Brown, Jared Hansen (IPUC), Chris Drake, Scott Kinney, Jason Thackston,
Darrell Soyars, Sean Bonfield, Thomas Dempsey, Jeff Schlect, Ben Otto (ICL), Meghan
Pinch, Grant Forsyth, Tina Jayaweera, and Tomas Morrissey (PNUCC).
Any notes in italics are short response from the presenter for each topic.

Introductions, John Lyons
No questions

Final Resource Needs Assessment (formerly L&R), John Lyons
Steve Johnson: Are Colstrip and Lancaster the deficits in 2026/27?
James Gall: The loss of Colstrip for 220 MW and Lancaster for 222 MW are the two
major changes from the 2025-2027 period.

2020 Renewable RFP Update, Chris Drake
Steve Johnson: Under proposed CR103 for IRP planning with CETA requirements, if
the deficit is within 4 years you will need an RFP. I notice your capacity need is just over
4 years out. Do you anticipate issuing another RFP after this one?
James Gall: The resource strategy may call for resources ahead of need or it may call
for a renewable or non-capacity need. If this RFP can satisfy those needs that could
push this earlier resource shortage further out. If there’s still a need after this RFP is
complete, we’ll need to do an RFP in the next year or so since it will be close to that 4-
year window if something new needs to be built.
Steve Johnson (Slide 5): I’m concerned with that being late given the general region is
also needing resources around this date and we will be in a capacity crunch. We’re
waiting, but that could pose a problem with coal retirements and everyone else being in
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 520 of 1105
the same boat at the same time. Rather, could you smooth purchases out ahead of time
as opposed to buying just before the need?
James Gall: You have the same concerns we do.
Jason Thackston: Can’t time these perfectly. We need to ensure reliability which
guides the timing to early rather than to later acquisition while trying to balance
affordability, etc.

Portfolio Modeling Overview, James Gall
Ben Otto via chat: Avista – can you send out a copy of this portion of the presentation
materials? Thank you. An email was just sent with the updated slide decks. Thanks
John and Lori. The PRiSM slides are the ones I was looking for.
James Gall: It will be sent out shortly to the entire TAC.
Peter Sawicki: How do you look at new technology such as renewable hydrogen?
James Gall: The list of resources included in our model, forecast of costs, and forecast
of how costs change are all on our website and are out there for input from the TAC.
Two renewable hydrogen options were included.
Mike Louis: Quite a bit of additional functionality that you’re building into PRiSM, what
steps are you taking for validation of that model?
James Gall: How would you define validation?
Mike Louis: How well does the model represent operations and how well is the model
producing something that represents reality.
James Gall: That is the benefit of building the model in Excel. It is easy to audit and
how it works is transparent. You can see the L&R balances, if the costs are reasonable,
and it is reviewed by internal and external folks to make sure the model is producing a
result based on the math we intended. There may be some disagreement with
assumptions for inputs, but you can review the math. For operations, we are not
proposing any changes to our operations based on PRiSM modeling. This is a financial
exercise to determine who pays for resources in the future as opposed to how we
currently allocate resources.
Mike Louis: That helps a lot James. At the end of the day with my experience in
modeling, I’d like to see a validation plan to ensure validity for all the tests and the
results to see if they are reasonable. I’d like to see a comprehensive plan of how you
thought of this ahead of time and how you tested it.
James Gall: We’ll talk about a lot of these tests this afternoon. The scenarios test the
validity of the model a lot.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 521 of 1105
Steve Johnson: Is this the model you’d use if you were examining DR in a single
source context? Would you still use this model?
James Gall: No, this is a planning tool. If you were choosing what to acquire, we’d use
something else – a more granular model. You could use this model for capacity value,
etc. You could put in resource options from an RFP to see what it’d pick, but it might be
better to use a more granular tool.
Steve Jonson: This model is enough to give you some value such as capacity value?
James Gall: Yes, it gives you the financial value, but not the reliability value.
Operational value and reliability value, you could put all of that into this tool and let it
pick your options. If you have a large amount of choices that are vastly different, this
tool would work; if the choices are more similar, you’d probably want a different tool.
Michael Eldred: Does that apply to new resources also?
James Gall: New resources are different and can be acquired just for one state or
allocated between both states. Operationally, they are the same, but the payments for
them could be different.
Mike Louis: For Colstrip, are you modeling those units separately?
James Gall: Yes, we are modeling Colstrip units with separate capital and O&M costs.
Ben Otto: Are you saying there is already a certain amount of efficiency in the load
forecast and some can be selected? And what happens if it can choose more than is
out there?
James Gall: We don’t know what energy efficiency is out there so we iterate. We keep
rerunning it until the amount selected and the amounts in the CPA are essentially the
same. Limits of econometric as opposed to end use forecast.
Jennifer Snyder: To make sure I have this correct about end effects for Grant’s load
forecast, no matter how much cost-effective energy efficiency is selected, it’s never
going to reduce it?
James Gall: It’s not going to change significantly. Grant does make assumptions on
how customers change their use through the use per customer numbers.
Grant Forsyth: I’m on the call. There are specific factors that reduce use per customer
and some that can’t be explained, but it could be “efficiency”. There is some amount of
energy efficiency I’m projecting going forward.
Jennifer Snyder: Ok, thank you. A follow up on that. How does that dynamic work with
DR?
James Gall: Good segue to the next slide. We have no historical DR programs [non-
pilot size], so DR doesn’t affect load for the forecast. DR is treated differently from that
point of view. EVs could be a concern.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 522 of 1105
Grant Forsyth: There is nothing explicit for EVs. The load forecast assumed the
amount used per year per customer.
Steve Johnson: I’m trying to understand what kind of assumptions of cost and value
streams you put into your model.
James Gall: We assume Mid-C prices and not necessarily the value of selling any
beyond what goes into California.
Steve Johnson: CPUC regulatory action, that hasn’t been taking into account, but
maybe taking that into account has an impact on price. Would you put that into your
model?
James Gall: We value based on our market at the Mid-C, we’re only trying to value for
intra-hour energy. Other values are outputs based on your choices as compared to
energy-only resources.
Amy Wheeless via chat: Do you make any assumptions about consumers buying CTA
2045 enabled water heaters due to markets (e.g., someone in the CdA area buying a
water heat at a Spokane Lowes)?
James Gall: We’re not considering that.
Ben Otto: How are some results showing a shared system and then some are assigned
for each state?
James Gall: Let’s table that math to this afternoon’s discussion.
Ben Otto: If you sell RECs and return the revenue to Idaho customers, what about
increments of more than 20% being sold to Washington?
James Gall: We could show that. I will add it to the list. It would be available renewable
energy times the REC price.
Charlie Inman via chat (slide 15): For market transactions, the Washington CETA defines the emission rate of “unspecified market purchases” as 0.437 metric tons per
MWh. Will this be included at all in the modeling process?

James Gall: Not at this time. It is in CETA, but is related to a different use and we’re
looking at this for the future. That default emissions number is based on a gas turbine.
We’re including the average market emissions rate for all purchases and storage. We’re
unable to model general purchases now, but will look at this for the future. There is an
opportunity for adjustment.

Jennifer Snyder: I don’t recall what that is in CETA. It’s in section 7. I will read it over lunch.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 523 of 1105
Steve Johnson: There is not a lot of time for debating when it comes to the evaluation for transmission. For resources, you aren’t including any end-of-life resources past the end of useful life, have you thought that there is an advantage to someone else
operating a resource, if it isn’t your least cost resource?

James Gall: Transmission costs are levelized; even if a resource does go offline, we
benefit from the available transmission. There is quite a bit of advantage if someone
else operates with all of that transmission interconnection. You’ve identified a head
scratcher of what could happen, but how can you model everything.

After lunch

Ben Otto: James, I thought of a question at lunch. What $/MWh is Avista using for the social cost of carbon? Is it the Washington UTC adopted numbers?

James Gall: Ben, the social cost of carbon is the Washington adopted value for CETA.
It is available on the website in Excel form by year.

Draft PRS and Scenarios, James Gall
Steve Johnson: We are really on a roll now. This raises questions about whatever
happened to the idea for super freezing air.
James Gall: Liquid air shows up in some scenarios for some options in the future.
Hydrogen showed up rather than liquid air due to the resource assumption differences
for peak credits. Both are about storage, but fuel replacement as well. Hydrogen
assumes no constraints and gets a peak credit; whereas, liquid air has some constraints
– while there is an air storage tank, we might not be able to refill it quickly.
Stave Johnson: Thanks. That’s informative.
Peter Sawicki: What does “both” mean?
James Gall: Both means the resource serves both states. It serves 65% Washington
and 35% Idaho.
Peter Sawicki: For the 2029 resource picks, is that additive? Yes, but we could amend
that later.
James Gall (slide 16): DR is cumulative, but the rest of the resources are shown when
they show up in the portfolio. DR programs need to start earlier than they are needed to
give time to sign customers up for the program.
Darrell Soyars: How are transmission costs built in for each resource like in Montana
where they would be further away?
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 524 of 1105
James Gall: It’s complicated, we talked about it briefly earlier today. One avenue is the
Colstrip transmission line where we own rights for a little less than 200 MW. Another is
NorthWestern Energy transmission which could be a wheel. Other resources could be a
wheel request or a capacity build out.
Ben Otto: You said some amount of the gas [generation] is driven by capacity needs.
What is the amount of hours? Is this a capacity shortfall for a few hours or for several
months? What can we see?
James Gall: We looked at 1-hour, multiple hours, etc. When we calculate peak credits,
we run that through an 8760 to get the 5% LOLP. We need resources with long
duration winter generation capability to make sure we have resource adequacy. There
are several hours and they are definitely in the November to February period and during
hours 14 - 18, but I can’t tell you the exact hours. It’s difficult to have a resource
adequate system.
Jennifer Snyder: I’m wondering at the avoided cost in 2022 if on-peak is cheaper than
off-peak, or does it switch partway down.
James Gall: If I’m remembering correctly from the last TAC meeting, the amount of
solar added to the entire system in California, Oregon, Nevada, Arizona and other spots
in the west; the new solar is likely to drive prices in the middle of the day to zero or
negative prices.
Steve Johnson: I have a question or recommendation. Is it possible to add the rate of
return adders to PPAs after the modeling analysis?
James Gall: Yes, it’s possible. I think I’ve heard of 3 to 4 more scenarios today and I
already have 20 more. It can be done, but not sure if they will be done in time to file this
IRP. It depends on whether we’ll have time to fit these all in
Steve Johnson: It might be better to have a portfolio as bid by bidders less the rate of
return adders so we can compare the two.
James Gall: It won’t change the result much, but it will change the avoided cost
Amy Wheeless: Can you remind me of the timeline for next steps?
James Gall: The next meeting is in two to three weeks. We are using the PRS
resources in the current model. There will be a draft IRP out on January 4th. We are
hoping to include new resources if the 2020 Renewable RFP contracts are signed in
time for the draft release in January, but we may need to modify a lot by then.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 525 of 1105
Draft 2021 Preferred Resource Strategy
James Gall, Electric IRP Manager
Technical Advisory Committee Update Meeting
December 16, 2020
DRAFT
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 526 of 1105
Safe Harbor Statement
This document contains forward-looking statements. Such statements are subject to a variety of risks,
uncertainties and other factors,most of which are beyond the Company’s control, and many of which could
have a significant impact on the Company’s operations, results of operations and financial condition, and
could cause actual results to differ materially from those anticipated.
For a further discussion of these factors and other important factors,please refer to the Company’s reports
filed with the Securities and Exchange Commission.The forward-looking statements contained in this
document speak only as of the date hereof.The Company undertakes no obligation to update any forward-
looking statement or statements to reflect events or circumstances that occur after the date on which such
statement is made or to reflect the occurrence of unanticipated events.New risks,uncertainties and other
factors emerge from time to time, and it is not possible for management to predict all of such factors,nor
can it assess the impact of each such factor on the Company’s business or the extent to which any such
factor, or combination of factors, may cause actual results to differ materially from those contained in any
forward-looking statement.
DRAFT
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 527 of 1105
Other Caveats
•Clean Energy Transformation Act (CETA) rules and requirements are not complete.
–This draft PRS uses Avista’s best estimate of known requirements.
•Avista is negotiating with the 2020 renewable Request for Proposals (RFP) shortlist bidders
–This may change the results of the resource if a contract is signed.
•IRP resource options are primarily “new” resource options-RFP will determine whether or
not existing resources can be acquired at similar or lower cost than “new” options.
•Avista may not be able to physically retire or exit certain resources as the IRP PRiSM model
determines because of contract limitations.
•No future state specific resource cost allocation agreement has been made.
•Forward looking rates include non-modeled power supply cost escalating at 2% per year-
–DO NOT TAKE THIS AS A RATE FORECAST
–This is for informational purposes only
DRAFT
3
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 528 of 1105
Cumulative Energy Efficiency End Use Results (GWh)
DRAFT
4
WA ID WA ID WA ID
Appliances 0.3 0.1 3.5 0.8 11.6 2.7
Cooling 5.6 0.5 36.8 3.2 53.1 9.1
Electronics 1.1 0.2 14.1 4.8 25.2 9.3
Exterior Lighting 4.1 1.4 24.1 7.8 36.3 14.3
Food Preparation 0.1 0.0 2.2 0.4 5.9 0.9
Interior Lighting 20.3 13.0 100.1 49.3 171.1 89.6
Miscellaneous 1.3 0.3 11.2 2.8 22.9 5.5
Motors 4.9 3.9 35.3 25.6 41.3 28.8
Office Equipment 0.6 0.0 3.3 0.0 5.8 0.0
Process 0.7 0.1 4.1 1.1 4.5 1.4
Refrigeration 8.2 0.3 60.2 2.3 69.4 2.6
Space Heating 12.6 3.6 120.3 30.8 171.1 40.6
Ventilation 5.1 0.7 29.8 5.2 44.8 12.5
Water Heating 4.3 1.5 62.8 8.6 114.2 10.6
Total 69.2 25.6 507.8 142.9 777.1 227.8
2023 2031 2045
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 529 of 1105
Cumulative Energy Efficiency Segment Results (GWh)
DRAFT
5
WA ID WA ID WA ID
College 2.1 0.7 11.0 4.2 15.5 7.5
Grocery 6.8 0.2 47.4 1.4 56.3 1.7
Health 2.7 0.9 14.3 5.1 22.8 10.3
Industrial 12.0 8.4 62.5 42.8 91.4 62.9
Large Office 6.5 1.3 43.1 8.8 66.8 16.4
Lodging 1.3 0.6 8.6 2.9 12.5 4.9
Low Income 3.0 1.8 37.3 10.8 53.7 13.5
Miscellaneous 5.1 1.9 35.6 10.7 54.5 19.1
Mobile Home 0.6 0.2 5.5 1.5 8.7 2.3
Multi-Family 0.4 0.2 7.5 1.3 16.3 2.2
Restaurant 2.1 0.2 14.9 1.6 19.8 2.3
Retail 5.6 2.0 35.7 10.3 52.7 17.9
School 2.6 0.1 16.6 0.4 26.5 0.8
Single Family 13.8 5.1 139.6 29.1 234.2 43.7
Small Office 2.2 1.1 16.1 7.4 25.1 13.5
Warehouse 2.3 0.9 12.1 4.7 20.2 8.9
Total 69.2 25.6 507.8 142.9 777.1 227.8
2023 2031 2045
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 530 of 1105
31.7 69.2
110.9
159.9
215.1
274.5
336.5
396.9
454.8
507.8
0
100
200
300
400
500
600
2022 2023 2024 2025 2026 2027 2028 2029 2030 2031
Gi
g
a
w
a
t
t

H
o
u
r
s
Selected EE
Pro Rata 10yr
Higher Washington Energy Efficiency Goals
More Aggressive Ramp Rates & Higher Avoided Costs
DRAFT
6
101.6
Biennial Conservation Target
(MWh)
Based on
2021 IRP
Based on
2020 IRP
CPA Pro-Rata Share 101,566 72,338
Distribution & Street Light Efficiency 219 504
EIA Target 101,785 72,842
Decoupling Threshold 5,119 3,642
Total Utility Conservation Goal 106,904 76,484
Excluded Programs (NEEA)-12,896 -14,016
Utility Specific Conservation Goal 94,008 62,468
Decoupling Threshold -5,119 -3,642
EIA Penalty Threshold 88,889 58,826
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 531 of 1105
24-yr Levelized Avoided Cost for Energy Efficiency
DRAFT
7
$0
$20
$40
$60
$80
$100
$120
Le
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2
0
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$
/
M
W
h
Energy Value
$0
$20
$40
$60
$80
$100
$120
$140
$160
Le
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2
0
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$
/
k
W
-yr
Capacity Value
$0
$20
$40
$60
$80
$100
$120
$140
Le
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$140
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$
/
k
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-yr
Capacity Value
Washington Idaho
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 532 of 1105
Winter (January) Capacity Position (MW)
Assumes Colstrip 3 & 4 are removed from the portfolio from 2022 to 2041 due to economic results of this study
8
Item 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041
New Load Estimate 1,706 1,712 1,716 1,720 1,725 1,729 1,733 1,738 1,743 1,748 1,753 1,758 1,764 1,770 1,775 1,782 1,790 1,798 1,807 1,816
Planning Margin 273 274 275 275 276 277 277 278 279 280 280 281 282 283 284 285 286 288 289 291
Reserves + Regulation 137 137 136 136 136 137 137 137 137 138 138 138 139 139 139 140 140 141 141 138
Oper. Reserves Hydro Credit -17 -17 -13 -13 -13 -13 -12 -12 -12 -8 -8 -8 -8 -7 -7 -7 -7 -7 -7 -7
Net Requirement 2,099 2,106 2,114 2,119 2,125 2,130 2,135 2,141 2,147 2,158 2,164 2,170 2,177 2,184 2,192 2,200 2,210 2,220 2,231 2,238
Long Term Sales -101 -101 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Long Term Purchases 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Clark Fork River 798 798 798 798 798 798 798 798 798 798 798 798 798 798 798 798 798 798 798 798
Spokane River 163 163 163 153 165 165 165 165 165 165 165 165 165 165 165 165 165 165 165 165
Mid-Columbia Contracts 228 227 147 146 145 144 142 135 135 63 63 64 64 64 64 64 64 64 64 64
PURPA Contracts 78 78 78 78 78 78 78 78 78 78 78 78 78 78 78 78 78 78 78 78
Palouse 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5
Rattlesnake Flats 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 0
Adams Nielson Solar 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Placeholder 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Placeholder 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Coyote Springs 2 318 318 318 318 318 318 318 318 318 318 318 318 318 318 318 318 318 318 318 318
Lancaster 283 283 283 283 283 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Colstrip (3)0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Colstrip (4)0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Kettle Falls 47 47 47 47 47 47 47 47 47 47 47 47 47 47 47 47 47 47 47 47
Kettle Falls CT 11 11 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Boulder Park 1-6 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 0
Rathdrum 1 88 88 88 88 88 88 88 88 88 88 88 88 88 88 88 88 88 88 88 88
Rathdrum 2 88 88 88 88 88 88 88 88 88 88 88 88 88 88 88 88 88 88 88 88
Northeast A&B 66 66 66 66 66 66 66 66 66 66 66 66 66 66 0 0 0 0 0 0
Net Position 5 -4 -2 -17 -12 -301 -307 -320 -326 -409 -415 -421 -428 -435 -509 -517 -527 -536 -547 -587
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 533 of 1105
Demand Response
Program Washington Idaho
Time of Use Rates 2 MW (2024)2 MW (2024)
Variable Peak Pricing 7 MW (2024)6 MW (2024)
Large C&I Program 25 MW (2027)n/a
DLC Smart Thermostats 7 MW (2031)n/a
Third Party Contracts 14 MW (2032)8 MW (2024)
Behavioral 1 MW (2041)n/a
Total 56 MW 15 MW
Notes:
1) Programs in another state for the benefit of the other state are not modeled
2) Operationally programs are likely for both states regardless of timing
3) 2027 start date is effectively 11/1/2027
DRAFT
9
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 534 of 1105
2022-2025 Supply-Side Resource Changes
2022: Economic to exit out of Colstrip 3 & 4 (Both States)
2023: 100 MW of Montana Wind (WA)
2024: 100 MW of Montana Wind (WA)
2025: No Action
NOTE: Renewable RFP may change this strategy
DRAFT
10
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 535 of 1105
2026-2029 Supply-Side Resource Changes
2026/27:12 MW Upgrade Kettle Falls (Both States)
283 MW Lancaster CCCT contract ends Nov 2026 (Both States)
126 MW NG SCCT (Both States)
85 MW NG SCCT (ID)
2028: 100 MW Montana Wind (WA)
2029:No Action
NOTE: Renewable RFP may change this strategy
DRAFT
11
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 536 of 1105
2030-2033 Supply-Side Resource Changes
2030:No Action
2031:75 MW Hydro Contract Renewal (WA)
2032:No Action
2033:No Action
DRAFT
12
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 537 of 1105
2034-2037 Supply-Side Resource Changes
2034:No Action
2035:5 MW Rathdrum CT Upgrade (Both States)
66 MW Northeast Retires (Both States)
2036:87 MW NG SCCT (Both States)
2037:No Action
DRAFT
13
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 538 of 1105
2038-2041 Supply-Side Resource Changes
2038:100 MW Solar + 50 MW 4-hour Lithium-ion Battery (Both States)
2039:No Action
2040:No Action
2041:25 MW Boulder Park Retires (Both States)
100 MW Montana Wind (WA)
36 MW Natural Gas Reciprocating Engine (ID)
DRAFT
14
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 539 of 1105
Draft Preferred Resource Strategy Selection (MW)
DRAFT
15
Note: Storage resources include 16-Hour Liquid Air Energy Storage and 4-Hour Lithium-ion.
Does not include results of 2020 Renewable RFP.
Nameplate MW 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 Total
Shared System Resource
NG CT - - - - - 126 - - - - - - - - 87 - - - - - - - - - 213
Solar - - - - - - - - - - - - - - - - 100 - - - - - - - 100
Storage Added to Solar - - - - - - - - - - - - - - - - 50 - - - - - - - 50
Wind - - - - - - - - - - - - - - - - - - - - - - - - -
Storage - - - - - - - - - - - - - - - - - - - - - - - - -
Hydrogen - - - - - - - - - - - - - - - - - - - - - - - - -
Other- (Clean Capacity)- - - - - - - - - - - - - - - - - - - - - - - - -
Thermal Upgrade - - - - 12 - - - - - - - - 5 - - - - - - - - - - 17
Hydro - - - - - - - - - - - - - - - - - - - - - - - - -
Washington
NG CT - - - - - - - - - - - - - - - - - - - - - - - - -
Solar - - - - - - - - - - - - - - - - - - - - 117 122 - 149 388
Storage Added to Solar - - - - - - - - - - - - - - - - - - - - 58 61 - 75 194
Wind - 100 100 - - - 100 - - - - - - - - - - - - 100 - - - - 400
Storage - - - - - - - - - - - - - - - - - - - - - - 12 - 12
Hydrogen - - - - - - - - - - - - - - - - - - - - - - - - -
Other- (Clean Capacity)- - - - - - - - - - - - - - - - - - - - - - - - -
Thermal Upgrade - - - - - - - - - - - - - - - - - - - - - - - - -
Hydro - - - - - - - - - 75 - - - - - - - - - - - - - - 75
Idaho
NG CT - - - - - 85 - - - - - - - - - - - - - 36 - - - - 122
Solar - - - - - - - - - - - - - - - - - - - - - - - - -
Storage Added to Solar - - - - - - - - - - - - - - - - - - - - - - - - -
Wind - - - - - - - - - - - - - - - - - - - - - - - - -
Storage - - - - - - - - - - - - - - - - - - - - - - - 10 10
Hydrogen - - - - - - - - - - - - - - - - - - - - - - - - -
Other- (Clean Capacity)- - - - - - - - - - - - - - - - - - - - - - - - -
Thermal Upgrade - - - - - - - - - - - - - - - - - - - - - - - - -
Hydro - - - - - - - - - - - - - - - - - - - - - - - - -
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 540 of 1105
Draft State Total Resource Selection (MW)
DRAFT
Nameplate MW 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 Total
Washington
NG CT - - - - - 83 - - - - - - - - 57 - - - - - - - - - 140
Solar - - - - - - - - - - - - - - - - 66 - - - 117 122 - 149 454
Storage Added to Solar - - - - - - - - - - - - - - - - 33 - - - 58 61 - 75 227
Wind - 100 100 - - - 100 - - - - - - - - - - - - 100 - - - - 400
Storage - - - - - - - - - - - - - - - - - - - - - - 12 - 12
Hydrogen - - - - - - - - - - - - - - - - - - - - - - - - -
Other- (Clean Capacity)- - - - - - - - - - - - - - - - - - - - - - - - -
Thermal Upgrade - - - - 8 - - - - - - - - 3 - - - - - - - - - - 11
Hydro - - - - - - - - - 75 - - - - - - - - - - - - - - 75
Idaho
NG CT - - - - - 128 - - - - - - - - 30 - - - - 36 - - - - 195
Solar - - - - - - - - - - - - - - - - 34 - - - - - - - 34
Storage Added to Solar - - - - - - - - - - - - - - - - 17 - - - - - - - 17
Wind - - - - - - - - - - - - - - - - - - - - - - - - -
Storage - - - - - - - - - - - - - - - - - - - - - - - 10 10
Hydrogen - - - - - - - - - - - - - - - - - - - - - - - - -
Other- (Clean Capacity)- - - - - - - - - - - - - - - - - - - - - - - - -
Thermal Upgrade - - - - 4 - - - - - - - - 2 - - - - - - - - - - 6
Hydro - - - - - - - - - - - - - - - - - - - - - - - - -
16
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 541 of 1105
Clean Energy Shares (aMW)
System Clean Resource Percentage
2022: 74.8%
2027: 78.3%
2045: 85.5%
Excludes Clean Market Purchases
DRAFT
17
Av
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a
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e

M
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a
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System
Av
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M
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s
Washington
Av
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a
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M
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s
Idaho
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 542 of 1105
Annual Average Least Reasonable Cost Rate Forecast
NOTE: Estimated rates only using 2% annual rate increase for non-modeled costs
DRAFT
18
0.000
0.020
0.040
0.060
0.080
0.100
0.120
0.140
0.160
0.180
0.200
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 543 of 1105
Greenhouse Gas Forecast with Draft PRS
Note: Assumes Colstrip exits the portfolio in 2022
DRAFT
19
Mi
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M
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n
s
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 544 of 1105
New Supply-Side Resource Avoided Costs
DRAFT
20
Year
Flat
($/MWh)
On-Peak
($/MWh)
Off-Peak
($/MWh)
Clean
Energy
Premium
($/MWh)
Capacity
Premium
($/kW-Yr)
20 yr Levelized $25.85 $25.20 $26.72 $14.04 $80.3
24 yr Levelized $27.18 $26.39 $28.22 $14.50 $86.6
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 545 of 1105
Portfolio Scenario and Market Sensitivity Analysis
James Gall, Electric IRP Manager
Technical Advisory Committee Update Meeting
December 16, 2020
DRAFT
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 546 of 1105
Safe Harbor Statement
This document contains forward-looking statements. Such statements are subject to a variety of risks,
uncertainties and other factors,most of which are beyond the Company’s control, and many of which could
have a significant impact on the Company’s operations, results of operations and financial condition, and
could cause actual results to differ materially from those anticipated.
For a further discussion of these factors and other important factors,please refer to the Company’s reports
filed with the Securities and Exchange Commission.The forward-looking statements contained in this
document speak only as of the date hereof.The Company undertakes no obligation to update any forward-
looking statement or statements to reflect events or circumstances that occur after the date on which such
statement is made or to reflect the occurrence of unanticipated events.New risks,uncertainties and other
factors emerge from time to time, and it is not possible for management to predict all of such factors,nor
can it assess the impact of each such factor on the Company’s business or the extent to which any such
factor, or combination of factors, may cause actual results to differ materially from those contained in any
forward-looking statement.
DRAFT
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 547 of 1105
Scenario Descriptions
1.Least Reasonable Cost Strategy: Includes all requirements
2.Baseline Portfolio 1: Excludes CETA’s 2030 and 2045 goals
–Used for incremental cost calculation
3.Baseline Portfolio 2: Baseline Portfolio 1 + removal of SCC
–Energy Efficiency held constant from LCS
4.Baseline Portfolio 3: Baseline Portfolio 2 + removal of capacity constraints
–Energy Efficiency held constant from LCS
5.Clean Resource Plan (2027)
–Add constraint to meet or exceed 100% of all retail sales with clean energy
6.Clean Resource Plan (2045)
–Add constraint to meet or exceed 100% of all retail sales with clean energy
–All thermal resources must exit by 2044
–No new thermal resources
7.Social Cost of Carbon applied to Idaho
–Includes SCC as cost adder to generation and savings for EE using same method as Washington
State
DRAFT
3
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 548 of 1105
Scenario Descriptions (Continued)
8.Least Cost Plan-with low load growth
–Loads decline by 0.11% per year vs. +0.31% per year
9.Least Cost plan-with high load growth
–Loads increase by 0.73% per year vs. +0.31% per year
10.Least Cost Plan-w/ Northwest Resource Adequacy Market Peak Credits
–Use Regional Planning Margin of 12% & Regional Peak Credits
11.Heating Electrification Scenario 1
–WA customers electrify with exiting heating technology
12.Heating Electrification Scenario 2
–WA customers electrify using hybrid systems (i.e. NG furnace & electric HP & HPWH)
13.Heating Electrification Scenario 3
–WA customer electrify using technology without COP rates not falling below freezing temperatures
14.Least Cost Plan-with 2 time SCC prices
–Double of Social Cost of Carbon charge for Washington Only
DRAFT
4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 549 of 1105
Scenario Descriptions (Continued)
15.Colstrip serves Idaho customers through 2025
–Colstrip obligated to run through 2025 in both states
16.Colstrip serves Idaho customers through 2035
–Colstrip obligated to run though 2035 for Idaho
17.Colstrip serves Idaho customers through 2045
–Colstrip obligated to run through 2045 for Idaho
18.CETA delivers by the hour
–Approximates resource selection requiring clean energy delivery by hour
19.Social Cost of Carbon applied to net purchases/sales
–Includes SCC planning penalty on the net of market purchases/sales (2020 IRP assumption)
20.Average Market Emissions Rate applied to Energy Efficiency SCC
–Replaces incremental market emissions for average market emissions for SCC on EE (2020 IRP
assumption)
DRAFT
5
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 550 of 1105
Scenario Descriptions (Continued)
1a. Least Cost Plan with Climate Shift
–Re-optimized PRS with alternate load and generation forecast assuming warming temperatures
1b. Least Cost Plan with Social Cost of Carbon “Tax”
–Re-optimized PRS with market carbon tax on fossil fuel generation
6
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 551 of 1105
Scenario & Sensitivity List
Number Scenario Expected
Case
High N.
Gas Price
Low N.
Gas Price
Social
Cost Carbon Tax
Climate
Shift
1 Preferred Resource Strategy X X X X
2 Baseline Portfolio 1 (No CETA renewable targets)X
3 Baseline Portfolio 2 (No CETA renewable targets/SCC)X X X X
4 Baseline Portfolio 3 (No Capacity Constraints)X
5 Clean Resource Plan (100% Portfolio net clean by 2027)X X X X
6 Clean Resource Plan (100% Portfolio clean by 2045)X X X X
7 Social Cost of Carbon applied to Idaho X
8 Least Cost Plan-w/ low load growth X
9 Least Cost Plan-w/ low load growth X
10 Least Cost Plan-w/ Northwest Resource Adequacy Market Peak Credits X
11 Heating Electrification Scenario 1 X
12 Heating Electrification Scenario 2 X
13 Heating Electrification Scenario 3 X
14 Least Cost Plan-w/ 2x SCC prices X
15 Colstrip serves Idaho customers through 2025 X X X X
16 Colstrip serves Idaho customers through 2035 X X X X
17 Colstrip serves Idaho customers through 2045 X X X X
18 CETA deliver each hour X
19 Social Cost of Carbon applied to net Purchases/Sales X
20 Avg market emissions rate applied to SCC for EE X
1a Least Cost Plan-w/ climate shift X
1b Least Cost Plan-w/ SCC “Tax”X7
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 552 of 1105
Scenario Cumulative Resource Selection
DRAFT
8
1- Preferred
Resource
Strategy
2- Baseline 1 3- Baseline 2 4- Baseline 3 5- Clean Resource
Plan (2027)
6- Clean Resource
Plan (2045)
7- SCC Idaho 8- Low Load
Forecast
9- High Load
Forecast
10- RA Market 11- Electrificati
on 1
12- Electrificati
on 2
13- Electrificati
on 3
14- 2x SCC 15- Colstrip Exit 2025 16- Colstrip Exit 2035 17- Colstrip Exit 2045 18- Clean Energy
Delivered
Each Hour
19- SCC on Net P/S 20- Use Avg Mrkt
for EE SCC
1a- LCP w/ Climate
Shift
1b- LCP w/ SCC
Shared System Resource
NG CT 213 132 132 0 84 0 223 65 84 88 84 84 84 196 213 125 211 126 250 86 172 247
Solar 100 0 0 0 549 899 0 104 0 100 0 0 0 100 100 100 100 100 0 101 - 411 Storage Added to Solar 50 0 0 0 275 450 0 52 0 50 0 0 0 50 50 50 50 50 0 50 - 206
Wind 0 0 0 0 0 200 0 0 0 0 0 0 0 0 0 0 0 0 0 0 - 323
Storage 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 - 9
Hydrogen 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 - -
Other- (Clean Capacity)0 0 0 0 20 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 - -
Thermal Upgrade 17 17 17 0 17 12 17 17 21 17 17 17 17 17 17 17 17 17 17 17 21 17
Hydro 0 75 75 0 0 75 75 0 0 0 0 0 0 0 0 0 0 0 0 0 - 75
WashingtonNG CT 0 144 147 0 48 0 0 48 92 49 200 159 200 0 0 51 0 0 0 84 - -
Solar 388 0 0 0 26 0 496 131 493 552 277 536 425 379 388 388 387 788 120 389 372 -
Storage Added to Solar 194 0 0 0 0 0 248 0 246 94 138 268 212 189 194 194 194 369 60 194 111 -
Wind 400 0 0 0 400 400 400 400 514 300 894 628 796 400 400 400 400 700 616 400 400 350
Storage 12 68 68 0 24 312 22 0 113 0 486 279 474 23 12 22 13 512 22 12 21 865
Hydrogen 0 0 0 0 0 75 0 0 0 0 397 84 199 0 0 0 0 0 0 0 - -
Other- (Clean Capacity)0 0 0 0 0 96 0 0 20 0 20 20 20 0 0 0 0 100 0 0 - -
Thermal Upgrade 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 - -
Hydro 75 0 0 0 75 0 0 75 75 75 75 75 75 75 75 75 75 75 75 75 75 - DR Capability 56 104 97 3 56 104 57 49 49 34 49 49 49 57 56 56 56 56 49 56 49 35
EE- Winter Capacity 86 85 86 86 89 92 86 86 86 85 118 114 114 88 86 86 86 86 85 81 86 87
EE- Summer Capacity 92 92 92 92 100 101 93 92 92 96 121 97 99 94 92 92 92 92 92 79 97 115
Idaho
NG CT 122 97 97 0 148 0 57 135 194 148 91 132 91 127 122 165 73 158 92 169 120 -
Solar 0 0 0 0 200 250 0 0 0 0 0 0 0 0 0 0 0 0 0 0 5 -
Storage Added to Solar 0 0 0 0 0 50 0 0 0 0 0 0 0 0 0 0 0 0 0 0 - -
Wind 0 0 0 0 194 200 0 0 0 0 0 0 0 0 0 0 0 0 0 0 - 327 Storage 10 20 33 0 0 20 10 0 28 49 26 16 26 29 10 24 24 10 34 10 - 176
Hydrogen 0 50 50 0 0 232 50 0 50 0 100 50 100 0 0 0 0 0 0 0 - -
Other- (Clean Capacity)0 0 0 0 0 20 0 0 0 0 0 0 0 0 0 0 0 0 0 0 - -
Thermal Upgrade 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 - - Hydro 0 0 0 0 0 68 0 0 0 0 0 0 0 0 0 0 0 0 0 0 - -
DR Capability 15 18 20 2 16 20 19 8 16 19 19 18 19 18 15 9 9 15 15 19 16 8
EE- Winter Capacity 24 29 24 24 31 37 38 24 24 24 32 29 32 25 24 22 21 24 29 25 24 39
EE- Summer Capacity 13 13 13 13 26 30 35 13 13 20 15 13 15 13 13 11 11 13 13 13 35 53
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 553 of 1105
Existing Resource “Exits”
Note:
Assumes each plant is available through December 31st of the final year;
Exception: Lancaster PPA expires Oct 2026.
Dash indicates no plant exit in the study
DRAFT
9
1-
Preferred
Resource
Strategy
2-
Baseline
1
3-
Baseline
2
4-
Baseline
3
5- Clean
Resource
Plan
(2027)
6- Clean
Resource
Plan
(2045)
7- SCC
Idaho
8- Low
Load
Forecast
9- High
Load
Forecast
10- RA
Market
11-
Electrifica
tion 1
12-
Electrifica
tion 2
13-
Electrifica
tion 3
14- 2x
SCC
15-
Colstrip
Exit 2025
16-
Colstrip
Exit 2035
17-
Colstrip
Exit 2045
18- Clean
Energy
Delivered
Each
Hour
19- SCC
on Net
P/S
20- Use
Avg Mrkt
for EE
SCC
1a- LCP
w/
Climate
Shift
1b- LCP
w/ SCC
Coyote Springs 2 - - - - -2044 - - - - - - - - - - - - - - - -
Lancaster 2026 2026 2026 2026 2026 2026 2026 2026 2026 2026 2026 2026 2026 2026 2026 2026 2026 2026 2026 2026 2026 2026
Colstrip (3)2021 2021 2021 2021 2021 2044 2021 2021 2021 2021 2021 2021 2021 2021 2025 2035 -2021 2021 2021 2021 2021
Colstrip (4)2021 2021 2021 2021 2021 2021 2021 2021 2022 2021 2021 2021 2021 2021 2025 2035 -2021 2021 2021 2021 2021
Kettle Falls - - - - - - - - - - - - - - - - - - - - - -
Kettle Falls CT - - - - -2044 - - - - - - - - - - - - - - - -
Boulder Park 1-6 2040 2040 2040 2040 2040 2040 2040 2040 2040 2037 2040 2040 2040 2040 2040 2040 2040 2040 2039 2040 2040 2040
Rathdrum 1 - - - - -2044 - - - - - - - - - - - - - - - -
Rathdrum 2 - - - - -2044 - - - - - - - - - - - - - - - -
Northeast A&B 2035 2035 2035 2035 2035 2035 2035 2035 2035 2035 2035 2035 2035 2035 2035 2035 2035 2035 2035 2035 2035 2035
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 554 of 1105
2022-45 Levelized Revenue Requirement Delta from PRS
DRAFT
10
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 555 of 1105
Avg Energy Rate Delta from PRS (2030 & 2045)
DRAFT
11
Washington Idaho
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 556 of 1105
Annual Greenhouse Gas Emission
Avista Dispatched GHG Emissions
DRAFT
12
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 557 of 1105
Cost vs. GHG Tradeoffs
Change in Levelized Cost vs. Change in Levelized Net Emissions
DRAFT
13
-$80
-$60
-$40
-$20
$0
$20
$40
$60
$80
$100
$120
$140
-0.3 -0.2 -0.1 0 0.1 0.2 0.3 0.4 0.5
Ch
a
n
g
e

i
n

L
e
v
e
l
i
z
e
d

C
o
s
t

F
r
o
m

L
R
C
S

(
m
i
l
l
i
o
n
s
)

Change in Levelized GHG Emissions from LRCS (MMT)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 558 of 1105
2030 Risk Analysis
Measures 2030 standard deviation of “modeled” power cost compared to levelized cost
DRAFT
14 Note: PPA cost “fixed” for this analysis-meaning the PPA cost does not change with changes in delivered energy
$0
$10
$20
$30
$40
$50
$60
$1,040 $1,060 $1,080 $1,100 $1,120 $1,140 $1,160 $1,180 $1,200 $1,220 $1,240 $1,260
20
3
0

S
t
d
e
v

(
m
i
l
l
i
o
n
s
)
2022-2044 Levelized Revenue Requirement (Millions)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 559 of 1105
2045 Upper Tail Risk Analysis
95th percentile power cost minus mean power cost compared to levelized cost
DRAFT
15 Note: PPA cost “fixed” for this analysis-meaning the PPA cost does not change with changes in delivered energy
$0
$50
$100
$150
$200
$250
$300
$1,040 $1,060 $1,080 $1,100 $1,120 $1,140 $1,160 $1,180 $1,200 $1,220 $1,240 $1,260
20
4
5

T
a
i
l

R
i
s
k

(
m
i
l
l
i
o
n
s
)
2022-2044 Levelized Revenue Requirement (Millions)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 560 of 1105
Portfolio Results Summary
16
Scenario WA- PVRR
($ Mill)
ID-PVRR ($
Mill)
WA 2030
Rate
($/kWh)
WA 2045
Rate
($/kWh)
ID 2030
Rate
($/kWh)
ID 2045
Rate
($/kWh)
2030 Stdev
($ Mill)
2045 Stdev
($ Mill)
2045 Tail
Risk ($ Mill)
2045 GHG
Emissions
(MT)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 561 of 1105
Reoptimized Portfolios with Market Changes
•Studies how PRS would change given fundamental shift in energy
planning future.
•Stochastics are not modeled
–1a: Climate Shift
–1b: SCC Tax
Deterministic Scenario WA- PVRR
($ Mill)
ID-PVRR ($
Mill)
WA 2030
Rate
($/kWh)
WA 2045
Rate
($/kWh)
ID 2030
Rate
($/kWh)
ID 2045
Rate
($/kWh)
2045 GHG
Emissions
(MT)
17
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 562 of 1105
Sensitivity Comparative Analysis
Portfolio High NG
Prices
Low NG
Prices
SCC High NG
Prices
Low NG
Prices
SCC
1- Preferred Resource Strategy 6.1% -2.1% 5.5%-18% 16% -18%
3- Baseline 2 8.8% -3.0% 11.5%-18% 17% -18%
5- Clean Resource Plan (2027)3.6% -1.3% -0.1%-18% 16% -18%
6- Clean Resource Plan (2045)2.6% -0.9% 0.0%-12% 6% -25%
15- Colstrip Exit 2025 5.7% -2.0% 5.7%-14% 11% -23%
16- Colstrip Exit 2035 5.2% -1.8% 6.6%-11% 5% -30%
17- Colstrip Exit 2045 4.8% -1.7% 7.3%-10% 3% -31%
Portfolio High NG
Prices
Low NG
Prices
SCC High NG
Prices
Low NG
Prices
SCC
3- Baseline 2 1% -3% 4%1% 1% 1%
5- Clean Resource Plan (2027)1% 5% -2%-1% -2% -1%
6- Clean Resource Plan (2045)2% 7% 0%33% 13% 13%
15- Colstrip Exit 2025 0% 0% 0%23% 13% 11%
16- Colstrip Exit 2035 0% 1% 1%59% 32% 25%
17- Colstrip Exit 2045 -1% 1% 2%75% 41% 34%
Change in PVRR vs Expected Case Change in Levelized GHG MT vs
Expected Case
Change in PVRR vs PRS Change in Levelized GHG MT vs PRS
18
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 563 of 1105
2021 Electric IRP TAC 4.5 Meeting Notes, December 16, 2020
Shawn Bonfield, Lori Hermanson, Kein Keyt, Mike Morrison, Morgan Brummund, Dean
Sprattt, Amanda Ghering, Grant Forsyth, Clint Kalich, James McDougall, Jason
Thackston, Scott Kinney, Logan Callen, Corey Dahl, Dainee Gibson-Webb, Fred
Heutte, Jared Hansen, Ian McGetrick, John Chatburn, Jorgen Rasmussen, Katie Ware,
Michael Eldred, Mike Morrison, Rachelle Farnsworth, Shay Bauman, Jennifer
SnyderShelly McNeilly, Ricky Davis, Marrisa Warren, Joni Bosh, and Katie Pagan.
Notes in italics are the short resonses from the presenter.
Mike Morrison via chat: Please explain how Cumulative Energy Efficiency is
determined. (The Cumulative Part.)
James Gall: It is the total amount acquired to date of the prorata period.
Mike Morrison: What about retirements?
James Gall: The AEG forecast includes those retirements, so it’s included this in.
Energy efficiency trails off at the end of 2045 due to this.
Mike Morrison: What would be relevant are the cumulative amounts of what’s still in
place [for energy efficiency].
James Gall: I think that’s what is included here, but we should confirm with AEG.
Mike Morrison: What about capacity savings?
James Gall: Coming up.
Mike Morrison: Were the planning margin forecasts computed assuming increased
renewable use?

James Gall: Two ways to address that issue. Can either increase your planning margin
or decrease the peak credit on renewables. We chose to decrease the renewable peak
credit.

Fred Huette: On DR, can you speak to water heaters, heat pumps, etc., and what it looks like in terms of cost effectiveness?

James Gall: I was surprised that one wasn’t picked up. I would imagine that when we do our plan in 4 years, it’ll probably get selected. I think it was on the margin for this
IRP.

Fred Heutte: We will be recommending to move on this anyway.

Jennifer Snyder: A pilot CTA – 2045 program would likely make sense in the CEIP.
Yes.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 564 of 1105

Fred Heutte: You may already know this, but today in the Spokesman was a great
headline regarding Rattlesnake Flat Wind going online – congratulations.

James Gall: Thank you!

Mike Morrison: A couple of slides ago, planning margin reserves and regulation for new renewable resources. Can you walk through the Montana wind and what it was before and after you derate it?

James Gall: For 35% capacity credit at 200 MW, there is 70 MW of reliable energy. We exchange a gas CT for wind and then determine at what level we reach the LOLP of 5%. We then compare that amount of wind with the gas CT to get to the 5% LOLP. We had to discount wind by 35% to get to the same capacity. It declines as you get more
wind.

Mike Morrison: What about diversity of wind farms located all over?

James Gall: In Montana there is a large probablity of wind when it’s cold in Spokane, unlike northwest wind. Adding more wind decreases the capacity peak credit. Wind diversity helps with regulation, but there is still a capacity issue.

Mike Morrison: Your critical need seems to be in the winter. Why are you focusing on
winter?

James Gall: Sometimes those events aren’t Avista-driven. There was one summer
event in 2004. Winter is really our concern.

Mike Morrison: I think your IRP mentions others. Summer curtailments – you’ve had
three events in the summer.

Fred Heutte: Montana wind capacity factor is 35-40%, but you’re using ELCC to arrive at 35% peak capacity credit under stress conditions, is that correct? Yes. It’s a big state
and that doesn’t seem out of range. Have you considered matching wind with storage?

James Gall: We have not modeled matching wind with storage together, even though
we have modeled them separately. We have modeled solar plus storage. In our last
renewable RFP, we only had one combined solar plus storage proposal so we may look
at this for the next IRP. It may be more reduction or integration cost, we will look at this
in the next IRP.

Fred Heutte: You’re mostly hydro so you have more flexibility versus a stand alone
resource and some opportunities.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 565 of 1105

James Gall: Potentially

Fred Heutte: Clean energy premium would be added to the first three columns for
Washington?

James Gall: Yes, for example a new flat PPA would get both the clean energy premium and a capacity premium based on the profile of the resource.

Fred Heutte: What will happen with the off-peak and on-peak price flips?

James Gall: With all of the new solar in California and across the west, this causes the
prices to flip during the day with the result being no market to sell into during our
daytime peak. We have a super-peak price too in the evening peak.

Fred Heutte: On slide 15, in 2027 you have a CT for Washington and Idaho. How is this
one allocated to the states?

James Gall: It could be either. We tried to illustrate the driver for the resource need.

Jennifer Snyder: Baseline portfolio 2, you ran it four times.

James Gall: We used that scenario with different market variables to show how that
portfolio would do in a high or low gas price market, etc. This helps us understand the
limitations of that portfolio in different market futures.

Fred Heutte: What is the purpose of portfolio 18?

James Gall: If the commisssion decides by 2030 for clean energy needing to be
delivered to load by hour. This case was done to determine our best guess of how to do
that. It shows the cost impacts of that change from matching generation to load by the
hour.

Fred Heutte: Our understanding is it is not hour by hour, but it is interesting to look at.

Jennifer Snyder: What is the cost difference in Washington based on differing exit dates for Colstrip from 2022 to 2025?

James Gall: Because we have a shared system, the resource choices Idaho makes may impact Washington. Idaho may be long and may decide not to participate in some of the resources. That is why the costs could be lower or higher in Washington. It depends on if they stand alone on a resource choice versus splitting the costs with Idaho customers.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 566 of 1105

Fred Heutte: What are the minimum machine requirements to run PRiSM?

James Gall: There are not any machine minimums, but software requirements. Must
have a license and a modern machine with 4-8 gigs of RAM to probably solve in about 8
hours. Could get that down to minutes or to an hour with a better machine.

Fred Heutte: That gives a sense of the feasability so thanks for doing this.

Fred Heutte: I would like to try a scenario with a lot of batteries, DR, etc. and see what it takes to max out the system. Run one scenario with high performance, flexible and clean resources.

Mike Morrison: Could you explain ARAM?

James Gall: After the Janaury 4, 2021 filing we could schedule a one hour meeting to
go through that.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 567 of 1105
2021 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 5 Agenda
Thursday, January 21, 2021
Virtual Meeting

Topic Time Staff
Introductions 9:00 Lyons

Review Draft 2021 IRP 9:15 Lyons

Draft Resource Plans and Scenarios 9:45 Gall

2021 IRP Action Items 10:45 Lyons
Lunch 11:30 ARAM Model Overview 12:30 Gall Break 1:30
Clean Energy Implementation Plan and
Clean Energy Action Plan Discussion 1:45 Gall/Lyons

Draft IRP Comments from TAC 2:15

Adjourn 3:30
.........................................................................................................................................
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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 568 of 1105
2021 Electric IRP
TAC Introductions and IRP Process Updates
John Lyons, Ph.D.
Fifth Technical Advisory Committee Meeting
January 21, 2021
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 569 of 1105
Updated TAC Meeting Guidelines
•IRP team working remotely through the rest of this IRP, but still
available by email and phone for questions and comments
•Some processes are taking longer remotely
•Virtual IRP meetings until able to hold large group meetings again
•Joint Avista IRP page for gas and electric:
https://www.myavista.com/about-us/integrated-resource-planning
–TAC presentations
–Documentation for IRP work
–Past IRPs
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 570 of 1105
Virtual TAC Meeting Reminders
•Please mute mics unless speaking or asking a question
•Use the Skype chat box to write questions or comments
or let us know you would like to say something
•Respect the pause
•Please try not to speak over the presenter or a speaker
who is voicing a question or thought
•Remember to state your name before speaking for the
note taker
•This is a public advisory meeting –presentations and
comments will be recorded and documented
3
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 571 of 1105
Integrated Resource Planning
•Required by Idaho and Washington* every other year
•Guides resource strategy over the next twenty + years
•Current and projected load & resource position
•Resource strategies under different future policies
–Resource choices
–Conservation measures and programs
–Transmission and distribution integration for electric
–Gas and electric market price forecasts
•Scenarios for uncertain future events and issues
•Key dates for modeling and IRP development are
available in the Work Plans
4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 572 of 1105
Technical Advisory Committee
•The public process piece of the IRP –input on what to study, how to
study, and review of assumptions and results
•Wide range of participants involved in all or parts of the process
–Ask questions
–Help with soliciting new members
•Open forum while balancing need to get through all of the topics
•Welcome requests for studies or different assumptions.
–August 1, 2020 was the electric study request deadline for the 2021
IRP, new requests will be taken up in the 2023 IRP
•Planning team is available by email or phone for questions or
comments outside of TAC meetings
5
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 573 of 1105
2021 Electric IRP TAC Schedule
•TAC 1: Thursday, June 18, 2020
•TAC 2: Thursday, August 6, 2020 (Joint with Natural Gas TAC)
•TAC 2.5: Tuesday, August 18, 2020 Economic and Load Forecast
•TAC 3: Tuesday, September 29, 2020
•TAC 4: Tuesday, November 17, 2020
•TAC 4.5: Wednesday, December 16, 2020 –PRS & Scenarios
•TAC 5: Thursday, January 21, 2021
•Public Outreach Meeting: February 2021 (Do we still need this?)
•WUTC Public IRP Open Meeting: February 23, 2021
•TAC agendas, presentations, meeting minutes and IRP files
available at:
https://myavista.com/about-us/integrated-resource-planning
6
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 574 of 1105
IRP Documentation Available
•Draft 2021 IRP
•Avista Resource Emissions Summary
•Load Forecast
•CPA Measures
•Avista 2020 Electric CPA –Summary and
IRP Inputs
•Home Electrification Conversions
•Named Populations
•Natural Gas Prices
•Social Cost of Carbon
•High and Low Natural Gas Prices
•Market Modeling Results
•Climate Shift Scenario Inputs
•2021 IRP New Resource Options
•1 – Preferred Resource Strategy
•2 –Baseline 1 No CETA Renewable
Targets
•3 –Baseline 2 No CETA Renewable
Targets/SCC7
•4 – Baseline Portfolio 3 No Additions
•5 –Clean Resource Plan (2027)
•6 –Clean Resource Plan (2045)
•7 –Social Cost of Carbon Idaho
•8 & 9 – High and Low Load Forecasts
•10 –RA Program
•11 – 13 – Electrification 1, 2 & 3
•14 –2x SCC
•15 –Colstrip Serves Idaho through 2025
•16 –Colstrip Serves Idaho through 2035
•17 –Colstrip Serves Idaho through 2045
•18 –Clean Energy Delivery by Hour
•19 –SCC on Net Power Supply
•20 –Use Average Market for EE & SCC
•PRiSM Draft Results (12/7/20)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 575 of 1105
Process Updates
•January 4, 2021 –draft IRP released to TAC
•February 23, 2021 –WUTC hearing about draft IRP
–Discussion about need for another public outreach meeting
•March 1, 2021 –Comments from TAC on draft IRP due
•March 2021 –final IRP editing, printing and compilation of Appendices
–Inclusion of 2020 Renewable RFP results?
•April 1, 2021 –publication and submission of the 2021 Electric IRP with the
Idaho and Washington Commissions
–IRP and appendices will also be available on the Avista web site
•Commissions will schedule hearings and accept comments about 2021 IRP
8
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 576 of 1105
Today’s TAC Agenda
9:00 Introductions, Lyons
9:15 Review Draft 2021 IRP, Lyons
9:45 Draft Resource Plans and Scenarios, Gall
10:45 2021 IRP Action Items, Lyons
11:30 Lunch
12:30 ARAM Model Overview, Gall
1:30 Break
1:45 Clean Energy Implementation Plan and Clean Energy
Action Plan Discussion, Gall and Lyons
2:15 Draft IRP Comments from TAC
3:30 Adjourn
9
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 577 of 1105
2021 Electric IRP
Document Overview
John Lyons, Ph.D.
Fifth Technical Advisory Committee Meeting
January 21, 2021
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 578 of 1105
2021 Electric IRP Chapters
1.Executive Summary
2.Introduction, IRP Requirements, and Stakeholder Involvement
3.Economic and Load Forecast
4.Existing Supply Resources
5.Energy Efficiency
6.Demand Response
7.Long-Term Position
8.Transmission & Distribution Planning
9.Supply-Side Resource Options
10.Market Analysis
11.Preferred Resource Strategy
12.Portfolio Scenarios
13.Energy Equity
14.Action Plan
15.Clean Energy Action Plan
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 579 of 1105
2021 Electric IRP Chapters 1 –3
•Chapter 1: Executive Summary
–High level summary of 2021 IRP and PRS
•Chapter 2: Introduction, IRP Requirements, Stakeholder
Involvement
–TAC overview and rules guiding IRP development
–Major changes from the 2017 and 2020 IRPs
•Chapter 3: Economic and Load Forecast
–Economic conditions in Avista’s service territory
–Avista’s energy and peak forecasts
–Load forecast scenarios
3
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 580 of 1105
2021 Electric IRP Chapters Ch. 4 –6
•Chapter 4: Existing Supply Resources
–Avista’s resources
–Contractual resources and obligations
–Avista’s natural gas pipeline rights overview
•Chapter 5: Energy Efficiency
–Conservation Potential Assessment
–Energy efficiency modeling and selection
•Chapter 6: Demand Response
–Demand response potential study
–Overview of past demand response pilot programs
4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 581 of 1105
2021 Electric IRP Chapters Ch. 7 –8
•Chapter 7: Long-Term Position
–Reliability adequacy and reserve margins
–Resource requirements
–Reserves and flexibility requirements
•Chapter 8: Transmission and Distribution Planning
–Overview of Avista’s Transmission System
–Future Upgrades and Interconnections
–Transmission Construction Costs and Integration
–Merchant Transmission Plan
–Overview of Avista’s Distribution System
–Future Upgrades and Interconnections (includes project
evaluated with DER alternative)
5
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 582 of 1105
2021 Electric IRP Chapters Ch. 9 –10
•Chapter 9: Generation and Storage Resource Options
–New resource option costs and operating characteristics
–Potential Avista plant upgrades
•Chapter 10: Market Analysis
–Fuel price forecasts
–Regional resource additions
–Regional greenhouse gas emissions forecast
–Market price forecast
–Scenario analysis
6
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 583 of 1105
2021 Electric IRP Chapters Ch. 11 –13
•Chapter 11: Preferred Resource Strategy
–Resource Selection Process
–Preferred Resource Strategy
–Avoided cost
•Chapter 12: Portfolio Scenarios
–Portfolio Scenarios
–Portfolio cost, risk and environmental comparisons
•Chapter 13: Energy Equity
–Vulnerable populations
–Highly impacted communities
–Equity Advisory Group7
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 584 of 1105
2021 Electric IRP Chapters Ch. 14 –15
•Chapter 14: Action Plan
–Progress made on Action Items from the 2017 and 2020 IRPs
–IRP projects identified for the 2023 IRP
•Chapter 15: Clean Energy Action Plan
–Action items for CETA compliance between this and the 2023
IRPs
8
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 585 of 1105
2021 Electric Integrated Resource Plan Overview
James Gall, Electric IRP Manager
Fifth Technical Advisory Meeting, 2021 IRP
January 21, 2021
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 586 of 1105
Planning Environment
65% of load
2030/2045 clean energy mandate
Eliminate coal generation by 2025
Greenhouse gas emission penalties
Electrification push
Climate change considerations
Energy Equity
Distributed energy resource planning
35% of load
Least cost planning
Cost allocation
Market effects
State policy on Avista’s resources
2
CS2 Noxon
Colstrip
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 587 of 1105
Avista Reliability Needs
•Meet average coldest day’s peak hour load,
required reserves, and a 16% planning margin.
•Maintain 5 percent Loss of Load Probability.
•Regional effort to “pool” resources by creating
resource adequacy market may lower resource
need.
•~300 MW needed Nov-2026 (expiration of
Lancaster PPA)
•Additional 200 MW by 2036
•Aging Infrastructure & state policy pressuring
existing resources to close:
•Colstrip: 2025 (WA)
•Northeast CT: 2035
•Boulder Park: 2040
•Coyote Springs 2 CCCT/Rathdrum CTs ???
•Load growth & changes
•0.3% annual average growth.
•Large potential increases with electrification.
•Climate change might lower winter and increase
summer peak growth. (required study in next IRP)
-
500
1,000
1,500
2,000
2,500
3,000
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3
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4
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4
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System Winter Peak Hour
Load & Resource Balance
3
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 588 of 1105
Washington Clean Energy
Requirements
Non-Hydro Transfer Limit Hydro Transfer Limit
Total Existing Resources (Share)Retail Sales
Proposal Compliance Target
•Avista must create glidepath to 2030 clean
energy requirements.
•By 2030, 100% of “net” Washington retail
sales must “use” clean energy.
•20% can be met with unbundled RECs.
•might require real-time clean energy delivery.
•Resource Allocation
•Washington customers “buy” Idaho clean
energy share.
•Assumes Idaho’s wind/biomass may be sold
to WA without limitation.
•Assumes Idaho’s hydro purchases limited to
20% of sales beginning in 2030, then
declining.
•By 2045, 100% of Washington sales must
be served with clean energy.
•May require real-time clean energy delivery.
Washington Retail Sales &
Clean Resource Balance
4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 589 of 1105
Avista’s Clean Energy Targets
•In 2022, Avista generates clean energy
equal to 75% of retail sales.
•To meet 100% clean energy by 2027,
Avista must acquire ~320 aMW.
•800-1,000 MW of wind or 1,800 MW solar
(DC).
•Increases to over 510 aMW by 2045.
•Driven by load growth and expiring
contracts
•Avista goal is 100% real-time clean
energy delivery by 2045.
•Requires substantial investments in
energy storage to meet winter loads.
•Electrification of space & water heating
compound these issues.
Av
e
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a
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M
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System Annual Average
Sales & Clean Resource Balance
5
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 590 of 1105
Resource Options
Clean Resources
Wind
Solar
Biomass
Hydro
Geothermal
Nuclear
Fossil Fuel Resources
Natural gas peaker
Natural gas baseload
Coal (retention)
Customer generation
Demand Resources
Energy efficiency
Conservation
Load control
Rate programs
Fuel switching
Co-generation
Storage
Pumped hydro
Lithium-ion batteries
Liquid air energy storage
Flow batteries
Hydrogen
•Multiple factors drive resource
selection
•Cost or price
•Clean vs. fossil fuel
•Capacity value or “peak credit”
•Storage vs. energy production
•Location
•Availability (new vs. existing)
•Resource retirements
•Future capital investment
•Operating & maintenance cost/availability
•Fuel availability
•Carbon pricing risk
6 Resources in italics were not directly modeled for this IRP
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 591 of 1105
IRP’s Preferred Resource
Strategy -Supply Resources Resource Type Year State Capability
(MW)
Colstrip 2021 System (222)
Montana wind 2023 WA 100
Montana wind 2024 WA 100
Lancaster 2026 System (257)
Kettle Falls upgrade 2026 System 12
Natural gas peaker 2027 ID 85
Natural gas peaker 2027 System 126
Montana wind 2028 WA 100
NW Hydro Slice 2031 WA 75
Rathdrum CT upgrade 2035 System 5
Northeast 2035 System (54)
Natural gas peaker 2036 System 87
Solar w/ storage 2038 System 100
4-hr storage for solar 2038 System 50
Boulder Park 2040 System (25)
Natural gas peaker 2041 ID 36
Montana wind 2041 WA 100
Solar w/ storage 2042-2043 WA 239
4-hr storage for solar 2042-2043 WA 119
Liquid air energy storage 2044 WA 12
Liquid air energy storage 2045 ID 10
Solar w/ storage 2045 WA 149
4-hr storage for solar 2045 WA 75
Supply-side resource net total (MW)1,024
Supply-side resource total additions (MW)1,581
•IRP focuses on state goals and system
reliability to find lowest reasonable cost to
serve customer load.
•Develop resource needs assessment for
each state.
•State policies drive resource choices.
•Cost allocation based on state policies.
•Rate forecasts.
•Does not include resources in current RFP.
•Limits existing resources acquisition to 75
MW of additional regional hydro after 2031.
•Resources are selected either as system
resource (65%/35%) or state resource.
•Resources economically or contractually
expected to leave the Avista resource mix
are in green, natural gas-fired are in orange,
energy storage are in blue and clean
resources are in black.
7
Supply-Side Resource Changes
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 592 of 1105
IRP’s Preferred Resource
Strategy -Demand Resources
8
Energy Efficiency End Use Targets
Program Washington Idaho
Time of Use Rates 2 MW (2024)2 MW (2024)
Variable Peak Pricing 7 MW (2024)6 MW (2024)
Large C&I Program 25 MW (2027)n/a
DLC Smart Thermostats 7 MW (2031)n/a
Third Party Contracts 14 MW (2032)8 MW (2024)
Behavioral 1 MW (2041)n/a
Total 56 MW 15 MW
Demand Response
•63% of EE programs are C&I.
•77% of EE savings are from Washington.
•Washington avoided cost are $106/MWh plus
$151/kW-year for capacity.
•Driven by social cost of carbon and clean energy
avoided costs.
•Idaho avoided cost are $30/MWh plus $137/kW-
year for capacity.
•EE reduces winter peak by a 101% ratio to energy
savings and 97% ratio for summer.
•Washington 2022-23 target is 89,000 MWh; 50%
higher then previous biennium and higher than the
IRP’s two year cost effective acquisition amount.
•10-year target is 651 GWh or 74 aMW.
•Time of use and variable peak pricing requires
significant rate design effort leveraging metering
infrastructure.
•Demand response has limited reliability benefits
due to duration and call limitations.
Washington Idaho
Space Heating
Interior Lighting
Water Heating
Refrigeration
Cooling
Motors Ventilation
Exterior Lighting
Electronics
Miscellaneous
Process
Appliances
Office Equipment
Food
Preparation
Interior Lighting
Space Heating
Motors
Water Heating
Exterior Lighting
Ventilation
Electronics
Cooling
Miscellaneous
RefrigerationProcess
Appliances
Food PreparationOffice Equipment
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 593 of 1105
Preferred Resource Strategy
Costs and Rates
•Existing and new costs are allocated
between the states Avista serves.
•Washington rates are ~1 cent (12%) higher
per kWh today.
•Spread increases to 1.7 cents (15%) by 2030
and 2.0 cents by 2035.*
•Power costs rise well above inflation over
first 8 years due to clean energy and
capacity additions.
* Non-power related cost such as non-generation transmission,
distribution, and administration, are not directly modeled in the IRP and
assume a 2% annual growth rate.
9
0.000
0.020
0.040
0.060
0.080
0.100
0.120
0.140
0.160
0.180
0.200
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Overall Energy Rates
7%
5%
2%3%
2%
4%
4%
5%
6%
0%
2%2%
6%
3%
-1%
0%
1%
2%
3%
4%
5%
6%
7%
8%
2022-2025 2025-2029 2029-2033 2033-2037 2037-2041 2041-2045 2022-2045
WA ID
Power Cost Rate Change
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 594 of 1105
Clean Energy Shares (aMW)
•By 2030, Washington customers will have
clean energy equal to 100 percent of its
retail sales.
•Idaho’s clean energy share will lower both
Idaho and Washington rates.
•46% clean by 2030 and 60% clean by 2045.
•Clean energy as percent of system sales
increase to 78% by 2027 and 86% by
2045.
•Short-term clean energy purchase may
increase these estimates.
•Avista could purchase RECs to meet
2027 goals.
•Idaho customers have opportunity to sell
excess hydro RECs to reduce rates.
DRAFT
10
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Clean Energy Forecast
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 595 of 1105
Greenhouse Gas Emissions
Forecast
•2020 emissions were ~2.7 million metric
tons.
•Colstrip responsible for >1 million tons.
•Colstrip emissions would fall regardless as the
plant dispatch decreases over time.
•By 2030, emissions fall by 76 percent.
•Emissions from natural gas upstream
operations and construction are included
in this IRP.
•Washington load portion includes these
emissions priced at the social cost of carbon.
•WUTC recently ruled these emissions
accounting is encouraged but not required.
•Net emissions include market purchases
and sales at the regional emission
intensity rate.
DRAFT
11
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Annual Greenhouse Gas Types
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 596 of 1105
IRP Insights given uncertainty
•WUTC’s rulemaking regarding “use” of energy may
require significant market transformation and require
additional clean and storage resources.
•Electrification of Washington’s space and water heat
will significantly increase winter peak (up to ~700
MW) and annual energy (155 aMW) needs.
–New winter load will require significant investment in winter
capacity-such as natural gas turbines or long-duration storage.
–Energy rates from power acquisition rise 8% excluding non-power
costs such as T&D and home owner costs.
•Water heater load control may offer opportunities if
program costs decline (55+ MW).
–AC control is low cost option if summer peaks significantly
increase.
–Electric vehicle control is cost prohibitive now, but costs are
falling.
•Hydrogen-fired turbines show potential to be lowest
overall cost resource to serve winter loads in a 2045
100% clean energy future.
–Liquid air energy storage (LAES) and pumped hydro are better
nearer term options with intermediate energy duration options.
–Lithium-ion is low cost when coupled with solar or need for short
durations.
•A regional resource adequacy program is needed to
address regional reliability risk and lower Avista’s new
resource needs and costs (<1%).
–Resource mix could favor solar and hydro.
•Retaining Colstrip through 2025 increases cost by
1%.
–Tradeoff is higher power cost risk with an early exit.
•Meeting the clean energy goals increases total cost
by 5%.
–Idaho rates are 10% higher in 2027/ 28% higher in 2045.
–Washington rates are 4% higher in 2027/ 20% higher in 2045.
•Energy equity public engagement in Washington may
lead to new programs, resources, or investments.
–Equity budget requirements and limitations are unknown.
•Climate change (warmer temperatures) reduces
power costs and resource needs
–Hydro runoff better matches winter peaks and spill is less.
•Policy requirements with high carbon “taxes” support
higher clean energy levels and conservation
investments.
12
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 597 of 1105
Highlights
From the Preferred Resource Strategy
•Avista needs new clean resources to
comply with CETA.
•New capacity resources are required to
maintain reliability.
•Avista will need to pursue demand
response, rate design, and increase
energy efficiency.
•Exiting Colstrip is economic, but higher
risk.
•Long-duration storage is critical to meeting
100% clean energy objectives.
From Scenario Analysis
•Climate change lowers power costs.
•State/national policies will increase both rates
and costs.
•Electrification will significantly increase power
supply requirements. T&D and homeowner
costs are not estimated at this time.
•Real-time clean energy delivery will be
challenging for industry and current market
structure.
•Meeting Avista’s clean energy goals will be a
challenging without new technology or
increasing rates.
13
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 598 of 1105
Extra Slides
DRAFT
Tables & figures from Draft IRP of potential interest
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 599 of 1105
Scenario Analysis
Sorted by System PVRR (highest to lowest)
11- Electrification 1 14.7 10.1 4.5 0.131 0.188 0.109 0.158 34 88 132 0.57
13- Electrification 3 14.4 9.9 4.5 0.128 0.181 0.109 0.158 34 85 129 0.57
12- Electrification 2 14.0 9.5 4.5 0.127 0.176 0.109 0.155 34 71 115 0.56
6- Clean Resource Plan (2045)13.9 9.0 5.0 0.130 0.209 0.122 0.196 25 35 48 0.00
18- Clean Energy Delivered Each Hr 13.7 9.2 4.6 0.127 0.207 0.110 0.155 40 115 162 0.50
5- Clean Resource Plan (2027)13.7 8.8 4.9 0.129 0.176 0.121 0.166 24 56 100 0.50
9- High Load Forecast 13.5 8.9 4.6 0.123 0.164 0.104 0.142 38 70 122 0.56
7- SCC Idaho 13.3 8.7 4.6 0.126 0.175 0.112 0.161 39 82 143 0.50
17- Colstrip Exit 2045 13.3 8.7 4.6 0.127 0.173 0.108 0.154 34 72 127 0.89
16- Colstrip Exit 2035 13.3 8.7 4.6 0.127 0.174 0.108 0.153 34 85 148 0.53
19- SCC on Net P/S 13.3 8.7 4.6 0.126 0.174 0.110 0.153 40 84 148 0.54
15- Colstrip Exit 2025 13.3 8.7 4.6 0.127 0.173 0.110 0.153 40 87 150 0.54
14- 2x SCC 13.3 8.7 4.5 0.127 0.174 0.110 0.152 40 85 147 0.53
1- Preferred Resource Strategy 13.2 8.7 4.5 0.127 0.173 0.110 0.153 40 87 150 0.54
20- Use Avg Mrkt for EE SCC 13.2 8.7 4.5 0.126 0.172 0.108 0.153 40 88 154 0.54
10- RA Market 13.2 8.7 4.5 0.126 0.174 0.109 0.152 43 94 171 0.50
8- Low Load Forecast 13.1 8.6 4.5 0.130 0.186 0.113 0.163 44 101 178 0.48
3- Baseline 2 13.0 8.4 4.6 0.121 0.168 0.110 0.151 55 148 253 0.56
2- Baseline 1 13.0 8.4 4.6 0.121 0.168 0.110 0.152 54 148 254 0.56
4- Baseline 3 12.5 8.1 4.4 0.117 0.158 0.106 0.141 55 162 276 0.33
15
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 600 of 1105
$0 $2 $4 $6 $8 $10 $12 $14 $16 $18
4- Baseline 3
17- Colstrip Exit 2045
8- Low Load Forecast
16- Colstrip Exit 2035
20- Use Avg Mrkt for EE SCC
15- Colstrip Exit 2025
19- SCC on Net P/S
1- Preferred Resource Strategy
14- 2x SCC
10- RA Market
7- SCC Idaho
2- Baseline 1
3- Baseline 2
5- Clean Resource Plan (2027)
9- High Load Forecast
6- Clean Resource Plan (2045)
18- Clean Energy Delivered Each Hour
12- Electrification 2
13- Electrification 3
11- Electrification 1
PVRR (Bill $)
PV Tail 95 (Bill $)
Quantitative Risk PVRR + PV TailVar95 Risk
2030 Standard Deviation vs
Levelized Revenue Requirement
16
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 601 of 1105
Avoided Costs
2022 $20.37 $21.66 $18.65 $0.00 $0.00
2023 $18.71 $19.34 $17.89 $13.27 $0.00
2024 $18.73 $19.04 $18.32 $13.54 $0.00
2025 $19.99 $20.05 $19.92 $13.81 $0.00
2026 $23.74 $23.68 $23.82 $14.09 $0.00
2027 $24.63 $24.27 $25.12 $14.37 $115.10
2028 $25.67 $24.99 $26.58 $14.65 $117.40
2029 $26.65 $25.77 $27.83 $14.95 $119.80
2030 $26.46 $25.48 $27.78 $15.25 $122.20
2031 $27.63 $26.48 $29.15 $15.55 $124.60
2032 $28.02 $26.86 $29.57 $15.86 $127.10
2033 $29.30 $27.96 $31.08 $16.18 $129.70
2034 $29.42 $27.98 $31.33 $16.50 $132.20
2035 $30.47 $28.81 $32.68 $16.83 $134.90
2036 $32.10 $30.38 $34.41 $17.17 $137.60
2037 $31.95 $30.08 $34.45 $17.51 $140.30
2038 $34.46 $32.26 $37.39 $17.86 $143.10
2039 $34.77 $32.31 $38.04 $18.22 $146.00
2040 $35.67 $33.15 $39.01 $18.58 $148.90
2041 $38.23 $35.77 $41.52 $18.96 $151.90
2042 $38.71 $36.40 $41.79 $19.34 $154.90
2043 $39.27 $36.92 $42.40 $19.72 $158.00
2044 $46.82 $44.18 $50.34 $20.12 $161.20
2045 $46.45 $44.31 $49.28 $20.52 $164.40

17
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 602 of 1105
PRS Greenhouse Gas Intensity
18
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 603 of 1105
Initial Vulnerable Population
Areas
19
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 604 of 1105
Energy Forecast
(percent)
Expected Case 0.30
High Growth 0.70
Low Growth -0.10

20
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 605 of 1105
2021 Electric IRP
Action Items
John Lyons, Ph.D.
Fifth Technical Advisory Committee Meeting
January 21, 2021
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 606 of 1105
Summary of 2017 IRP Action Plan
•Generation Resource Related Analysis
–Continue to review existing facilities for opportunities to upgrade capacity and efficiency
–Model specific commercially available storage technologies
–Upgrade the TAC concerning the EIM study and Avista’s plan of action
–Monitor regional winter and summer resource adequacy, additional LOLP studies
–Post Falls redevelopment update
–Ancillary services valuation for storage and peaking technologies using intra hour
modeling capabilities
–Monitor state and federal environmental policies affecting Avista’s generation fleet
•Energy Efficiency and Demand Response
–Consider moving T&D benefits from historical to forward looking values
–Decide on potential and cost study for winter and summer residential DR programs
–Use the UCT methodology for Idaho energy efficiency programs
–Share list of energy efficiency measures with TAC prior to CPA completion
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 607 of 1105
Summary of 2017 IRP Action Plan
•Transmission and Distribution Planning
–Maintain existing Avista transmission rights
–Continued participation in BPA transmission rate proceedings
–Participate in regional and sub-regional efforts to expand
transmission system
–Coordinate IRP and T&D planning to evaluate alternative
technologies to solve T&D constraints
3
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 608 of 1105
2020 Resource Acquisition Action Items
•Determine plan for Long Lake expansion and file with
appropriate agencies concerning if the project meets CETA
and licensing issues
•Continued pursuit of pumped storage opportunities
•Conduct transmission network and air permitting studies for
contingency CTs if pumped hydro is not available
•2020 RFP for renewable energy capacity (2022-2023 online)
•2021 RFP for capacity resources (on-line by 2026)
•Additional studies for the eventual shutdown of Northeast CT
in 2035
4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 609 of 1105
2020 Analytical & Process Action Items
•Continued study of costs of intermittent resources, and financial
costs and capabilities of different resources to meet the variability
•Include greenhouse gas emissions from resource construction,
manufacturing and operations
•Investigate third-party market price forecast for use with future
IRPs
•Participate in CETA rulemaking
•Participate in development of regional resource adequacy
program
5
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 610 of 1105
2021 IRP Action Items
•Continue 2020 Action Items with shortened 2021 IRP
•Investigate consultant for hydro and load shift from climate
•Investigate integration of resource dispatch, resource selection
and reliability verification functions in IRP modeling
•Study natural gas supply issues and options for Kettle Falls CT
•Determine if distribution planning should be separate process
•Form an Equity Advisory Group
•Conduct existing resource market potential estimate of
amount and timing of existing resources through 2045
•Additional DR peak credit analysis
•Partner with a third-party to identify NEI benefits
6
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 611 of 1105
2021 Electric IRP
Modeling Process Overview
James Gall, IRP Manager
Fifth Technical Advisory Committee Meeting
January 21, 2021
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 612 of 1105
IRP Planning Models
Aurora
PRiSM
“Reliability”
Model (ARAM)
PowerWorld Synergi
Load
Forecast
Resource
Options
Transmission & Distribution Models will be discussed in TAC 3
Discuss in TAC 2
Supply-side: Today
Demand Side: TAC 2
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 613 of 1105
What is Reliability Planning
•Estimate the probability of failure to serve all load
–Avista’s reliability target is 95% of all simulations serve 100% of load and reserve
requirements
•Model randomizes events
–Hydro, weather (load, wind, resource capacity), forced outages
•Typically large sample size 1,000 simulations
•Can be used to validate if a portfolio is reliable
–Estimate the required planning reserve margin (PRM)
–May be used to estimate peak credits for new resources (ELCC)
•Gold standard: regional wide program with enforced requirements to
each utility
–Set required methodology, planning margin, and resource contribution
based on regional model
3
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 614 of 1105
2021 IRP Table 7.1: LOLP Reliability
Study Results without New Resources

Jan 0.6% 2.7% 10.5% 32.7%
Feb 0.1% 0.6% 4.2% 15.0%
Mar 0.0% 0.0% 0.5% 2.9%
Apr 0.0% 0.0% 0.0% 0.0%
May 0.0% 0.0% 0.0% 0.0%
Jun 0.0% 0.0% 0.0% 0.1%
Jul 0.0% 0.3% 1.7% 33.0%
Aug 0.0% 0.1% 0.6% 30.5%
Sep 0.0% 0.0% 0.0% 0.9%
Oct 0.0% 0.0% 0.0% 0.5%
Nov 0.0% 0.0% 0.7% 5.0%
Dec 0.8% 3.2% 7.1% 17.1%
Annual 1.4% 6.3% 21.2% 81.4%

4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 615 of 1105
Table 11.5: Reliability Metrics of PRS
LOLP 4.6% 5.4% 8.8% 5.2%
LOLH 1.45 hours 1.74 hours 2.89 hours 1.89 hours
LOLE 0.12 0.14 0.21 0.15
EUE 233 MWh 266 MWh 548 MWh 316 MWh
Total Events 126 148 228 160

5
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 616 of 1105
Scenario Analysis
# Scenario Year
Studied
LOLP LOLH LOLE EUE
1 PRS 2030 5.4%1.74 0.14 266
5 Clean Resource Plan (2027)2030 5.7%1.66 0.13 250
6 Clean Resource Plan (2045)2040 7.5%2.98 0.22 643
10 Resource Adequacy Program 2030 6.4%2.67 0.2 510
16 Colstrip Exit 2035 2030 5.7%1.77 0.14 287
11 Electrification Scenario 1 2040 TBD TBD TBD TBD
•Due to limited time, focus on scenarios with reliability implications
•Any other scenario we should look at?
6
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 617 of 1105
2021 Electric IRP
Clean Energy Action Plan
John Lyons, Ph.D.
Fifth Technical Advisory Committee Meeting
January 21, 2021
DRAFT
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 618 of 1105
Clean Energy Action Plan
The CEAP must:
1.identify and be informed by the utility’s ten-year cost-effective conservation potential
assessment;
2.if applicable, establish a resource adequacy requirement;
3.identify the potential cost-effective demand response and load management programs that
may be acquired;
4.identify renewable resources, non-emitting electric generation and distributed energy
resources that may be acquired and evaluate how each identified resource may be
expected to contribute to meeting the utility’s resource adequacy requirement;
5.identify any need to develop new, or expand or upgrade existing bulk transmission and
distribution facilities; and identify the nature and possible extent to which the utility may
need to rely on alternative compliance options, if appropriate.
•CEAP is available in chapter 15 of the 2021 IRP
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 619 of 1105
Energy Efficiency Savings
•508 GWh of cumulative energy efficiency or 61.3 aMW with T&D line loses.
•Reduce winter peak 64.3 MW and summer peak 69.5 MW.
3
Figure 15.1: Washington 10-year Energy Efficiency Target
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 620 of 1105
Resource Adequacy
•Participating in development of a regional resource adequacy program.
–16 percent winter peak and 7 percent summer peak planning margins, plus operating
reserves and regulation requirements.
–A resource adequacy program could reduce Avista’s new capacity needs by up to 70 MW in
2031 based on the current draft program design.
–Could reduce future resource acquisitions if successfully implemented.
•2021 IRP identifies 83 MW of natural gas-fired capacity for Washington by
November 1, 2026 to replace Lancaster PPA and maintain reliability.
•Future RFP may identify a lower cost clean resource.
4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 621 of 1105
Demand Response and Load Management Programs
•CEAP identifies new programs with the potential to reduce load by 37.6 MW by 2031.
•Begin in 2024 with time of use and variable peak pricing opt-in programs, estimated to be 12 MW by 2031.
•25 MW large commercial customer program offering is likely before the Lancaster PPA ends in 2026.
•Heating and cooling program starts in 2031 with 0.6 MW of savings and grows to over 6 MW by 2045.
•Future RFPs may identify other DR opportunities.
5
Program Washington
Time of Use Rates 3.1 MW (2024)
Variable Peak Pricing 8.9 MW (2024)
Large C&I Program 25.0 MW (2027)
DLC Smart Thermostats 0.6 MW (2031)
Total 37.6 MW (2031 Total)
Table 15.1: Demand Response and Load Management Programs
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 622 of 1105
Planned Clean Energy Acquisitions
6
2022 2023 2024 2025 2026 2027 2028 2029 2030 2031
Retail Sales 647 650 651 655 657 658 658 661 662 663PURPA22222222222222222222
Solar Select 6 6 6 6 6 6 0 0 0 0Net Requirement 619 623 624 628 629 631 636 640 641 642
Target Clean %80 80 85 85 90 90 95 95 100 100Clean Energy Goal 496 498 530 534 567 568 604 608 641 642
Owned Hydro 292 288 288 285 292 289 292 289 291 291Contract Hydro 96 95 65 66 65 64 63 58 59 23
Kettle Falls 24 23 23 21 23 21 22 20 21 19
Palouse Wind 24 24 24 24 24 24 24 24 24 24Rattlesnake Flat Wind 36 36 36 36 36 36 36 36 36 36
Adams Neilson Solar 0 0 0 0 0 0 6 6 6 6
Available Resources 473 466 436 431 439 434 441 433 436 399
Shortfall 23 33 94 103 127 134 163 174 204 242
Resource Forecast
Montana Wind 0 48 96 96 96 96 144 144 144 144Kettle Falls Upgrade 0 0 0 0 6 6 6 6 5 5Regional Hydro 0 0 0 0 0 0 0 0 0 31
ID AVA Ren. Purchase 23 0 0 7 25 32 13 25 42 41ID AVA Hydro Purchase 0 0 0 0 0 0 0 0 13 21Total Energy/RECs 23 48 96 103 127 134 163 175 204 242
Net Position 0 15 2 0 0 0 0 1 0 0
Total Clean Resource Need 23 48 96 103 127 134 163 175 191 180
Table 15.2: 2022-2031 Washington Clean Energy Targets (aMW)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 623 of 1105
Transmission & Distribution Improvements
•2021 IRP did not identify any significant transmission or distribution
improvements.
•Future transmission investment follows the 10-year plan in Appendix G.
•Two interconnection requests to Avista transmission to evaluate up to 200 MW
in Rathdrum and additional capacity at Kettle Falls.
–Kettle Falls interconnection request does not require any significant improvements.
–Rathdrum results will not be available until later in 2021.
•Reviewed potential resource acquisitions that could defer distribution
investments, but none were selected in this IRP.
•Will begin designing a public process for distribution planning in 2021.
7
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 624 of 1105
Energy Equity
•Developing plan for equitable distribution of benefits and reduced burdens on highly impacted
communities and vulnerable populations.
•Washington is identifying highly impacted communities and guidance on cost premiums.
–Avista developed methodology to identify vulnerable populations and will finalize after forming Equity
Advisory Group (EAG) in 2021.
–EAG will guide determination of communities and help design outreach and engagement to distinguish
and prioritize indicators and solutions.
–Committed to energy efficiency program pilot for vulnerable populations starting in 2021.
•Enhancements to energy efficiency cost effectiveness test include non-energy benefits.
•Avista prioritizes efficiency projects to improve resiliency and increase energy security in these
communities and gives a preference to renewable projects in vulnerable areas.
•Future request for proposals may yield more beneficial renewable resources.
8
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 625 of 1105
Cost Analysis
•IRP compares PRS cost to baseline portfolio without CETA requirements to show if
alternative compliance (2% cost cap) will be required.
•Avista expects to be below cap by $64 and $61 million for first two of the four-year
compliance periods.
9
Table 15.3: 2022-2024 Washington Cost Cap Analysis (millions $)
2021 2022 2023 2024 2025 TotalRevenue Requirement w/ SCC 651 651 669 700 705
Baseline 650 657 672 678
Annual Delta 1 11 28 27 67
Percent Change 0.2%1.7%4.2%4.0%2.5%
Four Year Max Spending 33 33 33 33 132
Comparison vs Annualized Cost Cap (32)(22)(5)(6)(64)
Table 15.4: 2025-2028 Washington Cost Cap Analysis (millions $)
2024 2025 2026 2027 2028 Total
Revenue Requirement w/ SCC 705 714 718 744 755 Baseline 688 709 721 731
Annual Delta 26 9 23 23 81
Percent Change 3.8%1.3%3.2%3.2%2.9%Four Year Max Spending 36 36 36 36 143
Comparison vs Annualized Cost Cap (10)(27)(13)(12)(61)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 626 of 1105
2021 Electric IRP
Clean Energy Implementation Plan (CEIP)
James Gall, Electric IRP Manager
Fifth Technical Advisory Meeting
January 21, 2021
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 627 of 1105
CEIP Overview
•File by October 1, 2021. (draft by Aug 15, 2021)
•Include current clean energy mix (2020).
•Set targets for energy efficiency, demand response and clean energy acquisition using median hydro
conditions.
•Include an assessment of indicators of Highly Impacted Communities and Vulnerable Populations
through work with the Equity Advisory Group.
•Include specific actions the utility will make to meet clean energy goals; including resource adequacy
and equity considerations.
•Calculate incremental costs.
•Create public participation plan (due on May 1, 2021).
•Interested parties have 60 days to provide written comments to the Commission.
•Commission will set an open public meeting; after adjudication, Commission will approve, reject or
approve with condition the utility’s CEIP or CEIP update.
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 628 of 1105
Public Participation
•A public participation plan must be filed with the WUTC on May 1, 2021.
•Avista will begin public participation on the CEIP toward the end of May
2021.
•All TAC members are welcome to join; please contact John Lyons at
[e-mail] or 509-495-8515 to be on the CEIP email list.
•Equity Advisory Group is currently forming.
–Ana Matthews leads this effort
–Contact her at 509-495-7979 or [e-mail] for more
information
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 629 of 1105
Clean Energy Implementation Plan (CEIP)
Details of Requirements
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 630 of 1105
WAC 480-100-640
CEIP Content –Filing Requirements, Interim Targets
1.Utility must file with the commission a CEIP by October 1, 2021, and every
four years thereafter; must describe the utility's plan for making progress
toward meeting the clean energy transformation standards
2.Interim targets.
a)Utility must propose a series of interim targets that
i.Demonstrate utility’s reasonable progress toward meeting the standards.
ii.Consistent with WAC 480-100-610 (4).
–EE, DR, Safety, Reliability, Balancing system, Equity
iii.Interim targets must be proposed in the form of the percent of forecasted retail sales of
electricity supplied by nonemitting and renewable resources prior to 2030 and from 2030-2045
b)Must include utility’s percentage of retail sales of electricity supplies by nonemitting and
renewable resources in 2020 in the first CEIP it files.
c)Each interim target must be informed by the utility’s historic performance under median
water conditions
5
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 631 of 1105
3) CEIP Content –Specific Targets
a)Utility must specific targets for energy efficiency, demand response and
renewable energy.
i.EE target much encompass all other EE and conservation targets and goals required by
the Commission; must be described in the BCP; utility must provide forecasted distribution
of energy and nonenergy costs and benefits
ii.Must provide proposed program details, budget, measurement and verification protocols,
target calculations, forecasted distribution of energy and nonenergy costs and benefits for
the utility’s demand response target.
iii.Must propose the renewable energy target as a percent of retail sales of electricity
supplied by renewable resources, details of renewable energy projects or programs,
budgets, forecasted distribution of energy and nonenergy costs and benefits
b)Must provide description of technologies, data collection, processes,
procedures and assumptions used to develop targets
6
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 632 of 1105
4) CEIP Content –Customer Benefit Data
a)Identify highly impacted communities using the cumulative impact analysis
pursuant to RCW 19.405.140 combined with census tracts (Indian country).
b)Identify vulnerable populations based on adverse socioeconomic and
sensitivity factors developed through the Equity Advisory Group (EAG) process
and public participation plan; describe changes from the utility’s most recently
approved CEIP.
c)Include proposed or updated customer benefit indicators and associated
weighting factors related to WAC 480-100-610(4)(c) such as energy benefits,
nonenergy benefits, reduction of burdens, public health, environment,
reduction in cost, energy security and resiliency. Customer benefit indicators
and weighting factors must be developed consistent with the EAG process and
public participation; describe any changes from the most recently approved
CEIP.
7
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 633 of 1105
5) CEIP Content –Specific Actions
Include specific actions the utility will take over the implementation period; actions
must meet and be consistent with the clean energy transformation standards and
be based on the utility’s CEAP and interim/specific targets; specific action items
must be presented in a tabular format providing
a)General location, if applicable, proposed timing, estimated cost, whether resource will be
located in a highly impacted community, will be governed by, serve or benefit highly
impacted communities or vulnerable populations in part or in whole.
b)Metrics related to the RA including contributions to capacity or energy needs.
c)Customer benefit indicator values, or a designation as nonapplicable, for every customer
benefit indicator described in section (4) (c)
8
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 634 of 1105
6) CEIP Content –Narrative Description of Specific
Actions
CEIP must describe how the specific actions:
a)Demonstrate progress toward meeting the standards.
b)Demonstrate consistency with the standards in 480-100-610(4)
i.An assessment of current benefits and burdens on customers, by location and population, and
the projected impact of specific actions on the distribution of customer benefits and burdens
during the implementation period.
ii.Description of how the specific actions in the CEIP mitigate risks to highly impacted communities
and vulnerable populations and are consistent with the longer-term strategies and actions
described in the utility’s most recent IRP and CEAP
c)Consistent with proposed interim and specific targets;
d)Consistent with the IRP;
e)Consistent with the resource adequacy requirements and a narrative describing how the
resources identified in the most recent RA assessment conducted or adopted by the utility
demonstrates that the utility will meet its RA standard;
9
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 635 of 1105
6) CEIP Content –Narrative Description of Specific
Actions (continued)
f)Demonstrate how the utility is planning to meet the clean energy transformation standards
at the lowest reasonable cost such as
i.Utility’s approach to identifying lowest cost portfolio of specific actions that meet the requirements
as well as its methodology for weighting considerations
ii.Utility’s methodology for selecting the investments and expenses it plans to make over the next 4
years that are directly related to the utility’s compliance with clean energy transformation
standards and demonstrate investments represent a portfolio approach to investment plan
optimization
iii.Supporting documentation justifying each specific action identified in the CEIP
10
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 636 of 1105
CEIP Content
7.Include a projected incremental cost as outline in WAC 480-100-660 (4).
8.Detail the extent of TAC/EAG or other public participation in the development
of the CEIP.
9.Describe any utility plans to rely on alternative compliance mechanisms as
described in RCW 19.405.040 (1) (b)
10.If the utility proposes to take the early action coal credit, it must satisfy the
requirements in that statutory provision by
–Demonstrate the proposed action constitutes early action by presenting the analysis by
detailing with and without the proposed early action
–Compare both the proposed early action and the alternative against the same proposed
interim and specific targets
11
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 637 of 1105
11) CEIP Content –Biennial CEIP Update
•Utility must make a biennial CEIP update filing on or before November 1 of
each odd-numbered year that the utility does not file a CEIP.
•CEIP update may be limited to the BCP requirements.
•Must file its biennial CEIP update in the same docket as its most recently filed
CEIP and include an explanation of ow the update will modify targets in its
CEIP.
•Utility may file in the update other proposed changes to the CEIP as a result of
the IRP progress report.
12
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 638 of 1105
480-100-645
CEIP Review Process
1.Interested parties may file written comments with the Commission within 60
days of the utility’s filing.
2.Commission will set an open public meeting; after adjudication, Commission
will approve, reject or approve with condition the utility’s CEIP or CEIP update;
Commission may order, recommend or require more stringent targets.
a)Commission may adjust or expedite interim or specific target timelines.
b)Parties requesting the commission make existing targets more stringent or adjust the
existing timelines has the burden of demonstrating the utility can achieve the targets or
timelines.
13
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 639 of 1105
2021 Electric IRP TAC 5 Meeting Notes, January 21, 2021
Meeting Attendees: Andres Alvarez; Shawn Bonfield, Avista; Annette Brandon, Avista;
Terrence Browne, Avista; Corey Dahl; Thomas Dempsey, Avista; Grant Forsyth, Avista;
Annie Gannon, Avista; Amanda Ghering, Avista; Dainee Gibson-Webb, Idaho
Conservation League; Michael Gump, Avista; James Gall, Avista; Lori Hermanson,
Avista; Fred Heutte, NEWC; Clint Kalich, Avista; Kevin Keyt, IPUC; Scott Kinney,
Avista; John Lyons, Avista; Jaime Majure, Avista; James McDougall, Avista; Ben Otto,
Idaho Conservation League; Tom Pardee, Avista; Lance Kaufman (AWEC); Marissa
Warren, Idaho Office of Energy Resources; Michael Eldred, IPUC; Mike Louis, IPUC;
Mike Morrison, IPUC; Montoya Lina; Morgan Brummell; Rachel Farnsworth, IPUC; Shay
Bauman; Jennifer Snyder, WUTC; Terri Carlock, IPUC; Tina Jayaweera, NW Power
Council; Yao Yin, IPUC; Chip Estes; Joni Bosh, NWEC; Katie Pegan; Katie Ware.
Notes in italics are responses made by the presenter.

Introductions and 2021 IRP Process Updates, John Lyons
John Lyons (slide 6): Is the public open meeting that is scheduled for February 2021
still needed now that we have an open public meeting at the WUTC on February 23,
2021?
Rachel Farnsworth: What was going to be covered in the public outreach meeting?
Probably a high level overview of the draft IRP and an opportunity for the public to
comment before publishing it. I’m not sure I agree with not having that public meeting,
but will discuss it with our Idaho team. There was a lot of interest in participation for the
last IRP, so take that into consideration.
Ben Otto: I think providing a public opportunity to comment on the draft IRP before it is
finalized is a good idea.
James Gall (slide 7): If you want to run scenarios, get a hold of me because you’ll
need Gurobi and What’s Best licenses to make the models work. You can review the
results from the model runs without the licenses.
John Lyons: We do not have signed contracts yet for the successful bidders of the
2020 Renewables RFP and those contracts will change the near term PRS if signed.
For the results of the 2020 renewable RFP, what’s the cut-off to include them and
rewrite the IRP? Is it the end of January, sometime in February, or some other time?
Jennifer Snyder: If possible, at all, it’d be great to have it included, time allowing. If
there is only time for a letter or appendices about the contracts, that’d be ok too.
Ben Otto: What is the likelihood and scale of changes to the PRS that could come from
the RFP?
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 640 of 1105
James Gall: It doesn’t change the resource need, but it changes the resource mix in
the early years.
John Lyons: We are hoping to be finished with contracts by end of the first quarter.

Review Draft 2021 IRP, John Lyons
Jennifer Snyder: Chapter 13, the EAAG is referred to as the EEAG.

Draft Resource Plans and Scenarios, James Gall
Mike Morrison: Could we further discuss the definition of a 5% LOLP?
James Gall: Let’s defer that to the ARAM discussion.
Joni Bosh: What do the green and blue stand for?
Lori Hermanson: Green resources are being retired and blue storage resources are
being added.
Thomas Dempsey: Why is there a 2021 retirement of Colstrip?
James Gall: Models show retirement when it’s cost-effective, but it doesn’t mean
Colstrip will retire in 2021.
Katie Ware: Did you explore the sensitivity of a mix of lithium-ion and long-duration
storage?
James Gall: Excellent question. Lithium-ion and long-duration storage are all resource
options, so the model when looking at capacity need can choose from any of those
resources. Longer duration resources have a higher peak credit which is why it is
selected over lithium-ion, even though lithium-ion could be a cheaper resource. Lithium-
ion is lowest cost when combined with solar, but liquid air is best for long term storage.
Katie Ware: Is there a scenario of storage mixes. Yes, we’ll discuss it in detail later.
Yao Yin: Based on the table and modeling, there are different needs for different
resources. How does the company reconcile this when acquiring resources?
James Gall: It’s a real challenge for us. We identify the need, then need to determine
who [which state or system] is driving the need and who is paying for it. We definitely
need a company strategy on how to assign responsibility for recovery of new resources
and we need to figure out how to do that with the commissions.
Yao Yin: How do you decide what resource to acquire in reality when it comes to
operational decisions?
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 641 of 1105
James Gall: If we acquire all of these, we’ll operate them to meet load if needed.
Actual acquisitions are decided through a competitive process like an RFP.
Tina Jayaweera: Are DR impacts for both summer and winter? Yes, many impacts for
both summer and winter.
Yao Yin: For the DR and energy efficiency programs in the preferred program, are they
based on the third-party or the study?
James Gall: The third party determines the price and the potential and our model
selects the measures.
Yao Yin: Are they bundled? No. Is DR the same way?
James Gall: Yes, each individual measure, about 7,000 of them, can be selected. This
is the same by DR and by state.
Fred Heutte: I’m wondering about DR, CT2045 for new water heaters and heat pumps,
electric resistance, why didn’t these show up?
James Gall: The costs were given by AEG, it was the next resource in [just missed
being selected in this IRP]. The potential was quite large, but it was not competitive. If
the pricing comes down about 20% in the next plan, it’ll be selected.
Fred Heutte: I’m going to investigate AEG’s numbers as it doesn’t seem this would be
that expensive. In my view, utilities in Washington should just acquire these.
Tina Jayaweera: Thermostats may not save the same amount in summer as in winter,
is the 7 MW in the summer or winter?
James Gall: It’s the winter savings. I have the summer savings available too, but didn’t
show them here. They are in the supporting documents. Feel free to dig into them.
Jennifer Snyder: Have you done any analysis on bill impacts? The Washington rate is
higher but so is energy efficiency, does it make the comparison any different?
James Gall: Great question, I don’t have the answer. Maybe that’s something we can
investigate.
Fred Heutte: About the below the zero sales, can you walk through the math? My
sense is there will always be gas in the market, about half of a coal plant.
James Gall: There’s several methodologies, you’ve described one. We sell system
power, then incremental cost and emissions change. I try to keep things simple here.
For every MW sold, we estimate the amount of emissions the NW emits. It’s really an
unknown and I try to show it both ways. It goes away in 2025.
Fred Heutte: It’s a net sales, but if you didn’t sell, what’s the marginal analysis?
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 642 of 1105
James Gall: I agree. I’ve done it and it’s difficult. Average hourly emissions by our
system and the regional emissions. However, we can’t do that to that level with the
models we have. Maybe we can in the future. We have annual models so I don’t know
how much we bought or sold each hour.

Fred Heutte: Agreed, this is a first cut and gives us a sense. It’s not easy to do this
hourly. Ultimately, we need to land there. Hydro complicates this too.
Joni Bosh: So system power is unspecified power?
James Gall: Two types of power – Avista’s system power, sales and purchases. We
don’t know what we’re buying each hour so we’d have to determine a mix of this.
Mike Morrison: Do the liquid air energy storage systems currently in your portfolio
assume the existence of waste heat from thermal plants? Is this waste heat generated
by hydrogen or biomass? If so, does your modeling include these costs?
Thomas Dempsey: 100% renewable is not available yet.
Mike Morrison: You assume the use of waste heat to power the high temp side of the
engine, but the efficiency was above this.
Thomas Dempsey: I believe we provided an answer for that question, but I don’t have
that in front of me.
James Gall: Or we used a lower efficiency in this plan, but I’ll need to get back to you
on that.

2021 IRP Action Items, John Lyons
Fred Heutte: The Power Pool is having an update on resource adequacy next Friday.
I’ll add a link. [NWPP Resource Adequacy Program public webinar next Friday, Jan. 29,
1-2:30 pacific time https://www.nwpp.org/events/86 ]

John Lyons: Thanks for sharing that around.

Jennifer Snyder: I wanted to know if you are looking at other DER investments and how are you planning on doing those in the future?

James Gall: We currently evaluate those DER resource options in the plan. The challenge is they’re not getting selected from an economic point of view. Are there
additional economic or equity benefits that we need to study? Unless there’s a specific
reason to pick DERs due to a locational benefit to help with the economics, they’re not
going to be economic and will not be chosen. This takes quite a bit of time to study.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 643 of 1105
Jennifer Snyder: Other values will have to drive it to be accepted.

ARAM Model Overview, James Gall
Mike Morrison: What is your definition of LOLP?
James Gall: I’ll explain it when I open the model.
Lance Kaufman: If you’re unable to meet your load requirements, it counts as a loss of
load event. Can you explain this further?
James Gall: We track both ways – if we can’t meet our reserve obligations to WECC or
we can’t meet our load, both can occur at the same time.
Scott Kinney: It’s a NERC requirement that you have to maintain your operating
reserves to avoid blackouts across the whole system. For example, in California this
summer during the heat wave, they had to start shedding load. You have to shed load
to save the entire interconnection.
Thomas Dempsey: Can you clarify the question I thought I heard? Suppose we’re
carrying 100 MW of reserves, but we need 50 MW. If we have already used it, we no
longer have the 100 MW of reserve. Is that situation an event?
Scott Kinney: We can call on other reserves in the region.
Yao Yin: For existing and/or new resources, how do we determine the capacity?
James Gall: For both existing and new resources, and we will get to the capacity later
in the presentation.
Lance Kaufman: Can you explain the dispatch logic? Are things being co-optimized?
How is thermal, hydro/storage being re-dispatched?
James Gall: The model is not concerned with cost but with availability. It will dispatch
based on a priority of economics. Each resource is trying to serve that load equally but
in a high load event everything will run.
Lance Kaufman: Will you cover storage logic later?
James Gall: Yes. This is a reliability model. The first version was with no economics.
This model now has economics included.
Mike Louis: If the market is used to meet reserves, is the amount constrained?
James Gall: Essentially, from a market point of view, we’re using our reserves to meet
the load. We could buy from the market in the future to meet reserves.
Lance Kaufman: Is there a risk of having that flat so that it misrepresents reliability?
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 644 of 1105
James Gall: I haven’t tested that. There could be a couple of months where there could
be a reliability problem. I’m leaning toward it not being a big impact, but I don’t know for
sure without testing.
Andreas Alvarez: What timeframe is the model optimizing these storage resources?
James Gall: All 8760 at the same time. The model has perfect foresight, which is more
than reality.
Yao Yin: Where is the 16% planning margin located?
James Gall: It’s not an actual input or output. We’re going to talk about this more later.
Andreas Alvarez: When it’s storing, is it seeing a price for charging?
James Gall: Yes, there’s an economic charge for charging and dispatching storage. It
is set up with a very high price to not serve load, so it is optimizing to serve load. Really
only focusing on hours where there will be an hour needed.
Andreas Alvarez: It’s charged for that hour to avoid the $5,000.
Mike Morrison: How are storage efficiencies determined?
James Gall: Determined by what storage resource was chosen.
Mike Morrison: How does it keep track of when storage devices are charging and
dispatching?
James Gall: Showed the dispatching versus charging in the model. It can’t draw more
than what the limits are.
Mike Morrison: Is the model smart enough to say the battery isn’t charged enough or
what needs to be charged?
James Gall: The power of the What’s Best program is that it creates a linear equation
to solve for the parameters, subject to constraints, to minimize the cost to serve load.
Lance Kaufman: Could you clarify for the hourly load forecast, when you say you’re
looking at historical years, are you taking historic temperatures and putting them into the
current forecast?
James Gall: Yes. Load forecast with weather using actual data for a particular year. In
theory. We have to create a regression to create an hourly load shape and match that
with weather.
Lance Kaufman: Where would we look to see the details of this by year?
James Gall: Historical hourly loads are used to create a regression equation which is
used to multiply the historical daily temperatures to estimate the hourly loads included in
the model. Since the ARAM model includes proprietary data it can’t be shared.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 645 of 1105
Lance Kaufman: On the years tab, have you done analysis between the water year
and the load year?
James Gall: Yes, on an annual basis. On an annual basis there is no correlation, but on
a weekly basis, there could be correlation. We’re varying these inputs on an annual
basis. We chose not to put a correlation in there.
Andreas Alvarez: Is Montana wind assumed to be central or eastern?
James Gall: It is eastern Montana wind. I don’t recall which wind turbine was used.
James Gall: Yao asked earlier how this relates to planning margin. We are trying to get
as close to 5% LOLP as possible. So the question is how many resources or how much
market availability do I have to add to achieve this? Here we will put a constraint on how
much can come from the market. We’re concerned with really hot or cold days – those
are the days we’re concerned about market availability. If the temperature is above 80
or below 2 degrees, it triggers a market availability constraint. The 16% planning margin
is the amount of extra resources needed above our load assuming this constrained
market availability.
Andreas Alvarez: Will you be going over peak capacity contributions?
James Gall: If I reduced gas and increased wind to come up with the same LOLP that
would result in a 25% peak credit. The difficulty is when you add more wind the value of
the peak credit degrades.

Clean Energy Implementation Plan and Clean Energy Action Plan, James Gall
Yao Yin: Is there a separate preferred portfolio for each state?
James Gall: Our PRS identifies what resources are driven by each state, but all
resources are needed.
Yao Yin: In the ARAM model, do we look at the entire system? Yes.
Jennifer Snyder: Is John the main contact? Are you considering the CEIP being the
same team makeup as the IRP?
James Gall: We have not decided yet. We’ll be working on that.

Draft IRP Comments from TAC
Mike Morrison: I’ve perused the draft. You definitely listened to some of our last
comments and incorporated them. I appreciate that. I’ll be really looking at the capacity
calculations and making sure the assumptions make sense. Anything you can do to
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 646 of 1105
enlighten me would be helpful. Keep up the good work. This has been a really helpful
presentation.
James Gall: John is taking notes and we’ll be putting these on our website. We’ll
respond where we can today if possible and for sure later in the final IRP.
Yao Yin: A clarifying question, for the preferred portfolio on the list of system need and
by Idaho and Washington, did you mean that the final list includes all resources and this
slide identifies the drivers?
James Gall: Correct. The slide includes all preferred resources needed to serve the
system and the color of each resource identifies the driver as being system, Idaho or
Washington.
Jennifer Snyder: The UTC doesn’t necessarily expect you to meet everything in this
IRP since the rules just came out. Can you add in some narrative on the maximum
customer benefit scenario and what that might look like to help with the discussion
going forward?
James Gall: I don’t know if the drafters of the rule have an expectation of what they’re
expecting for that scenario. The definition of the maximum customer benefit scenario is
what I am challenged by. I’m puzzled on what it means.
Jennifer Snyder: You and I are right there on that. PSE is doing 150% of cost-
effectiveness for energy efficiency. I don’t necessarily think this is the way to go. If you
were going to increase the customer benefit, how would you maximize things?
James Gall: What is the meaning of customer benefit – reliability, financial, etc.? We’re
already solving for the maximum financial benefit. We’ll mull it over. I think we already
have the scenario like PSE.
Shawn Bonfield: The newly formed equity advisory group may inform this scenario
from that perspective. I see this as a narrative of how we’ll use that group.
Yao Yin: On the slide about all the chapter content, for chapter 13 on the use of the
preferred portfolio in determining avoided costs, did you mean for PURPA or for energy
efficiency?
James Gall: We meant for both. Avoided cost of our preferred strategy which could be
used for PURPA, energy efficiency or a supply-side resource. We will be adding the
estimated avoided costs showing how folks can calculate the avoided costs of their
particular resource.
Yao Yin: What is your justification of using the preferred portfolio of new resources
instead of existing resources?
James Gall: We have an existing resource stack, but if we had a new resource to
consider the cost we are avoiding would be from acquiring a new resource.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 647 of 1105
2021 Integrated Resource Planning
February 24, 2021
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 648 of 1105
Meeting Format
•5:00 to 6:00
–Welcome-Jason Thackston, SVP of Energy Resources
–Overview of Avista’s Electric Resource Plan-James Gall
–Overview of Avista’s Natural Gas Resource Plan-Tom Pardee
•6:00 to 6:30
–Attend first breakout session
•6:30 to 7:00
–Attend second breakout session
•This meeting will be recorded
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 649 of 1105
Objectives of Today’s
Meeting
•Overview of Avista’s electric and natural gas systems.
•Learn about considerations when planning to meet customer load.
•Explore Avista’s proposed resource plan for natural gas and
electric supply.
•Opportunity to ask questions and provide feedback in breakout
sessions.
•Poll questions to provide instant feedback.
3
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 650 of 1105
Avista also owns Alaska
Light & Power in
Juneau, AK
4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 651 of 1105
Maintaining Balance is
Important
EnvironmentReliability
Affordability
5
Poll
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 652 of 1105
Avista’s Clean Electricity Goal
Avista’s goal is to serve our
customers with 100 percent clean
electricity by 2045 and to have a
carbon-neutral supply of electricity
by the end of 2027
We will maintain focus on
reliability
and affordability
Natural gas is an important part of
a clean energy future
Technologies and associated
costs need to emerge and mature
in order for us to achieve our stated
goals
It’s not just about generation
6
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 653 of 1105
Providing Cleaner Natural Gas
•We are committed to reducing greenhouse gas emissions in our natural gas business too
•Achieving reductions requires an “all-of-the-above” approach:
•Gas supply and distribution opportunities like renewable natural gas
•Upstream strategies like targeted sourcing with suppliers
•Engagement with customers to increase energy efficiency, demand response, and voluntary
programs
•Just like our clean electricity goals, reducing greenhouse gas emissions in our natural gas system will
require advances in technology and reductions in the cost of those technologies
•Affordability will guide our decisions
7
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 654 of 1105
What is the Purpose of an IRP?
•Understand supply needs to serve
our customers over the next 20
years.
•Evaluate resource options to meet
future needs.
•Determine which resources are
best suited to meet customer need.
•Sets course for acquisition of
resources.
•Required to be filed with our
state regulating commissions
every two years.
•Allows for public feedback and
participation.
•Commissions acknowledge
plans but do not approve the
plans.
8
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 655 of 1105
Electric Integrated Resource Plan
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 656 of 1105
Production, $0.2763
Storage, $0.0236 Distribution, $0.2395
Common, $0.1682
What makes up your energy
rate?
Fixed Charge
Monthly connection
charge
Demand Charge
The highest use
over an hour in the
last 12 months
Energy Charge
The amount of
energy used over
the month
Begins with Cost
to Serve All
Customers Residential
Commercial
Large
Commercial
Industrial
Water
Pumping
Street
Lighting
Customer Type Pricing Type
El
e
c
t
r
i
c
Na
t
u
r
a
l

G
a
s
Production, $0.0412
Transmission, $0.0087
Distribution,
$0.0216
Common, $0.0172
Poll
10
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 657 of 1105
What fuels our generating
resources?
11
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 658 of 1105
Why does Avista need new
electric resources?
Resources
Load without EE + Contingency
Load with EE + Contingency
Meet System Winter Peak
Load
Non-Hydro Transfer Limit Hydro Transfer Limit
Total Existing Resources (Share)Retail Sales
Proposal Compliance Target
Meet Washington Clean Energy
Requirements
12
Avista also plan to meet summer peak conditions & to ensure it generates
enough energy over the course of the year in poor hydro conditions.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 659 of 1105
What are the available options
to meet our electric customer
obligations?
Clean Resources
Wind
Solar
Biomass
Hydro
Geothermal
Nuclear
Fossil Fuel Resources
Natural gas peaker
Natural gas baseload
Coal (retention)
Customer generation
Demand Resources
Energy efficiency
Conservation
Load control
Rate programs
Fuel switching
Co-generation
Storage
Pumped hydro
Lithium-ion batteries
Liquid air energy storage
Flow batteries
Hydrogen
13 Resources in italics were not directly modeled for this IRP
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 660 of 1105
Electric IRP’s Preferred
Resource Strategy over the
next 10 years
14
Generation
Portfolio
By end of 2025: Exit Colstrip
2023-24: Add new renewables (i.e. wind, solar, hydro)
2026-2027: Replace Lancaster natural gas plant (natural gas
generation is lowest cost option) &
increase capacity at the Kettle Falls Generating Station & Post Falls
2028: Add new renewable resources
(Montana wind)
2031: Acquire existing Northwest
Hydro Capacity
2035: Replace Northeast natural gas plant with upgrades to Rathdrum CT
and acquire new capacity
Energy
Efficiency
Energy Efficiency meets 68% of
future load growth
Industrial & commercial
customers provide 2/3 of
savings
Residential Single family home is largest single segment
Washington top targets:
Lighting, space heating, water
heating, refrigeration, and cooling
Idaho to targets: Lighting, space heating, and motors
Demand
Response
2024: Offer new rate programs
(opt-in)
(Time of use rates & variable
peak pricing)
2026/27: Industrial load
control
2031-32: Smart thermostat controls and commercial load control
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 661 of 1105
Avista’s Cleaner Future
-
200
400
600
800
1,000
1,200
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Existing Clean Resources RECs New Clean Resources Net Sales
-1.0
-0.5
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Current Resources
New Resources
Net Market Transactions
Upstream/Construction/Operations
Net Emissions
2019 Generated Emissions
Dispatched Emissions w/ Colstrip Operating to 2025
•Clean energy percent of system sales
increase to 78% by 2027 and 86% by
2045.
•By 2030, Avista’s greenhouse gas emissions fall
by 76 percent.
•2019 Northwest power emissions were 57 million
metric tons (Avista is 5.2% of those emissions).
•Power is 20% of all NW greenhouse gas
emissions.
15
Greenhouse Gas Emission Forecast
Clean Energy Forecast
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 662 of 1105
Natural Gas Integrated Resource Plan
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 663 of 1105
Existing Resources vs.
Peak Day Demand
-
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
100,000
MM
B
t
u
JP TF-2 Existing GTN Existing NWP Forecasted Peak Demand - Medford/Roseburg
-
50,000
100,000
150,000
200,000
250,000
300,000
350,000
MM
B
t
u
Existing GTN JP TF-2 Existing NWP Spokane Supply Forecasted Peak Demand for ID and WA
Idaho and Washington
Medford and Roseburg
17
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 664 of 1105
What are the available options
to meet our natural gas
customer obligations?
Clean Resources
Renewable Natural Gas
Hydrogen
Power to Gas
Fossil Fuel Resources
Natural gas
Coal gasification
Demand Resources
Energy efficiency
Conservation
Load control
Rate programs
Fuel switching
Storage
Jackson Prairie Storage Facility
Liquified Natural GasCompressed Natural Gas
18 Resources in italics were not directly modeled for this IRP
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 665 of 1105
Natural Gas System Cost vs
Carbon Adder
19
Poll
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 666 of 1105
Avista Natural Gas –A Cleaner
Future
2019 Retail Energy Delivered
Carbon Reduction Goals
(Oregon & Washington
Mi
l
l
i
o
n
s

o
f

M
T

C
O
2
e
Emissions with Climate Goals and EO
Expected Emissions MTCO2e
8,400
8,600
8,800
9,000
9,200
9,400
9,600
9,800
10,000
10,200
260
270
280
290
300
310
320
330
340
350
Electric Natural Gas
Th
o
u
s
a
n
d
s

o
f

M
W
h
Mi
l
l
i
o
n
s

o
f

T
h
e
r
m
s
Therms MWh
20
Oregon -Executive Order 20-04
•80% reduction by 2050
Washington -Goal
•95% reduction by 2050
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 667 of 1105
How do I get involved with the
IRP?
•Breakout rooms today
•Provide written comments to Avista’s planning
team by March 5th.
•Provide written comments to your state’s
commission
•Join Avista’s Technical Advisory Committees
–Electric IRP
–Natural Gas IRP
–Energy Efficiency
•Future participation opportunities
–Equity
–Energy Assistance
–Distribution Planning
How to learn more:
https://myavista.com/about-us/integrated-
resource-planning
Email: [e-mail]
Washington UTC
www.utc.wa.gov
Electric Docket: UE-200301
Natural Gas Docket: UG-190724
Idaho PUC
https://puc.idaho.gov/
Oregon PUC
www.oregon.gov/puc
21
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 668 of 1105
Breakout Sessions •Generation Resource Selection &
Reliability
–Stay here or use registration link
–Webinar ID: 82608251 3174
•Energy Efficiency & Demand
Response
–https://us02web.zoom.us/j/82664724856?pwd=QzdUMk9zUE1n
RjViYTlXRkJ5S2p5UT09
–Meeting ID: 826 6472 4856
•Affordability & Equity
–https://us02web.zoom.us/j/88435288369?pwd=bGtNK3JYbTBCcktCV
2JMRE1sT09CZz09
–Meeting ID: 884 3528 8369
•Environmental Topics
–https://us02web.zoom.us/j/89096065417?pwd=M0FzYWZHdjhT
QlRRR2xwOSs4M1ByZz09
–Meeting ID: 890 9606 5417
•Natural Gas Service
–https://us02web.zoom.us/j/84369554229?pwd=YkZJc0ZrUm91N
VFSanNJNmxPaVB4UT09
–Meeting ID: 843 6955 4229
•Two 30 minute break out room
opportunities.
•You can access breakout rooms
by using the links in the chat box
or stay in this session
•Passcode: Avista
•Short presentation by Avista staff
(5 minutes)
•Opportunity to ask Avista staff
questions or provide comments.
•Any questions not answered today
will be available on the IRP Avista
website by March 12.
•Limit of 300 participants in each
room
22
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 669 of 1105
Breakout Session Ground
Rules
•Due to the large response to this public meeting, please limit oral comments and questions to 30
seconds.
•Avista will try to answer all questions.
•Avista will also provide written responses if we cannot fully address the question.
•Comments will be acknowledged and recorded.
•If you would like to make a comment or ask a question.
•Use the “raise hand” feature in the meeting controls.
•We will call upon each person to speak.
•Please comment on areas within the breakroom topic
•Please do not repeat questions or comments.
•If you have the same comments-please indicate in the chat box or send an email to [e-mail] with
your comment
•In the event we do not get to your comment or question in the allotted time, please email
[e-mail]
•Please limit comments or questions to resource planning-this means in relation to the energy we serve
and not the delivery of energy. If you have these questions or any others please see.
•http://myavista.com/smartmeters
•[e-mail]23
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 670 of 1105
Resource Selection & Reliability Breakout Room
James Gall
Thomas Dempsey
Damon Fisher
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 671 of 1105
Resource Options
Clean Resources
Wind
Solar (utility and customer)
Biomass
Hydro
Geothermal
Nuclear
Fossil Fuel Resources
Natural gas peaker
Natural gas baseload
Coal (retention)
Customer generation
Demand Resources
Energy efficiency
Conservation
Load control
Rate programs
Fuel switching
Co-generation
Storage
Pumped hydro
Lithium-ion batteries (utility & customer)
Liquid air energy storage
Flow batteries
Hydrogen
•Multiple factors drive resource selection
•Cost or price
•Clean vs. fossil fuel
•Capacity value or “peak credit”
•Storage vs. energy production
•Location
•Availability (new vs. existing)
•Resource retirements
•Future capital investment
•Operating & maintenance cost/availability
•Fuel availability
•Carbon pricing risk
•Non-energy costs & benefits
•Social cost of carbon
•Locational siting
•Health, economic, and other benefits (still to
come)
25 Resources in italics were not directly modeled for this IRP
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 672 of 1105
Supply-Side Resource
Changes
Resource Type Year State Capability (MW)
Colstrip (Coal)By end of 2025 System (222)
Montana wind 2023 WA 100
Montana wind 2024 WA 100
Lancaster (Natural Gas)2026 System (257)
Post Falls Modernization (Hydro)2026 System 8
Kettle Falls upgrade (Wood-Biomass)2026 System 12
Natural gas peaker 2027 ID 85
Natural gas peaker 2027 System 126
Montana wind 2028 WA 100
NW Hydro Slice 2031 WA 75
Rathdrum CT upgrade (Natural Gas)2035 System 5
Northeast (Natural Gas)2035 System (54)
Natural gas peaker 2036 System 87
Solar w/ storage 2038 System 100
4-hr storage for solar 2038 System 50
Boulder Park (Natural Gas)2040 System (25)
Natural gas peaker 2041 ID 36
Montana wind 2041 WA 100
Solar w/ storage 2042-2043 WA 239
4-hr storage for solar 2042-2043 WA 119
Liquid air energy storage 2044 WA 12
Liquid air energy storage 2045 ID 10
Solar w/ storage 2045 WA 149
4-hr storage for solar 2045 WA 75
Supply-side resource net total (MW)1,032
Supply-side resource total additions (MW)1,589
•Long-term acquisition of new resources
will be conducted with a public request for
proposals (RFP).
•Avista recently added the Rattlesnake Flat
Wind project in 2020.
•Avista is currently working with clean
energy proposals from is most recent
RFP-this RFP will determine a portion of
the resource need in 2023-2024.
•New resource selection is determined by
deliverability and lowest economic cost
subject to resource policy requirements of
each state
26
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 673 of 1105
Energy Efficiency and Demand Response Breakout
Room
Ryan Finesilver
Leona Haley
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 674 of 1105
Energy Efficiency &
Demand Response
Energy Efficiency Program
Program designed to “incent”
customers to make energy efficiency
choices
Integrated Resource
Planning
Preferred Resource Strategy selects “measures” and sets target
Conservation Potential
Study to determine overall
conservation potential
4.4
6.1
7.5
10.0
10.0
11.5
19.0
21.9
31.9
35.4
42.0
60.9
62.7
64.3
135.3
Appliances (Res)
Miscellaneous (C&I)
Water Heating (C&I)
Interior Lighting (Res)
Miscellaneous (Res)
Other (C&I)
Electronics (Res)
Space Heating (C&I)
Exterior Lighting (C&I)
Ventilation (C&I)
Cooling (C&I)
Motors (C&I)
Refrigeration (C&I)
Water Heating (Res)
Space Heating (Res)
Interior Lighting (C&I)
10-YEAR GWH
CONSERVATION
POTENTIAL
Demand Response
Program Washington Idaho
Time of Use Rates 2 MW (2024)2 MW (2024)
Variable Peak Pricing 7 MW (2024)6 MW (2024)
Large C&I Program 25 MW (2027)n/a
DLC Smart Thermostats 7 MW (2031)n/a
Third Party Contracts 14 MW (2032)8 MW (2024)
Behavioral 1 MW (2041)n/a
Total 56 MW 15 MW
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Capacity
Energy Use
DR EventsDR Events
28
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 675 of 1105
Natural Gas Energy
Efficiency
Residential,
57%
Commercial,
41%
Industrial,
2%
0.03
0.04
0.16
0.33
0.42
1.27
4.8
5.14
5.78
0 1 2 3 4 5 6 7
HVAC
Appliances
Process Heating
Cooking
Ventilation
Other
Weatherization
Water Heating
Space Heating
Millions of Therms
29
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 676 of 1105
Affordability and Equity Breakout Room
Ana Matthews
Shawn Bonfield
Renee Coelho
Lisa McGarity
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 677 of 1105
Energy Rate Forecasts
Electric Rates:
•To meet Avista’s reliability requirements
and Washington clean energy policies
electric rates will increase.
•Today, Washington rates are ~1 cent
(12%) higher per “average” kWh.
•Going forward the difference between
Washington and Idaho rates will
continue to separate.
•Both Idaho and Washington customers
financially benefit by lower rates unless Idaho’s
share of clean resources are kept in Idaho.
Natural Gas Rates:
•Natural gas rate increases are driven by
increases in the price to acquire the
natural gas commodity and general
inflation to operate the system.
31
Electric Power Cost Rate Changes
Annual Average Natural Gas Rate Forecast
$1.0748
$1.0748 Idaho Washington Oregon
Note: Assumes 2%
annual increase in
non-energy resource costs
Av
e
r
a
g
e

C
h
a
n
g
e
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 678 of 1105
Energy Equity and Energy
Assistance Overview Bill Assistance
LIRAP Heat
LIRAP Senior/Disabled Outreach
Emergency Assistance
LIRAP Emergency Share
COVID-19 Hardship
Rate Discount
Senior/Disabled
To Be Implemented
Percent of Income Payment Plan
Arrearage Management Program
Conservation Education
Energy Fairs
Workshops
General and Mobile Outreach
Energy Efficiency
Low-Income Weatherization
•Washington State’s recently passed
legislation CETA (Clean Energy
Transformation Act) requires
•equitable distribution of energy benefits and
reduction of burdens to vulnerable
populations and highly impacted
communities;
•long-term and short-term public health,
economic, and environmental benefits and
the reduction of costs and risks;
•and energy security and resiliency.
•It is the intent of the legislature that in
achieving this policy for Washington,
there should not be an increase in
environmental health impacts to highly
impacted communities.
Low-Income Rate Assistance Program (LIRAP)
32
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 679 of 1105
Environmental Topics Breakout Room
John Lyons
Bruce Howard
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 680 of 1105
Avista’s Environmental
Footprint
-1.0
-0.5
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Current Resources
New Resources
Net Market Transactions
Upstream/Construction/Operations
Net Emissions
2019 Generated Emissions
Dispatched Emissions w/ Colstrip Operating to 2025
•By 2030, Avista’s greenhouse gas
emissions fall by 76 percent.
•2019 Northwest power emissions were
57 million metric tons (Avista is 5.2% of
those emissions).
•Power is 20% of all NW greenhouse gas
emissions.
•Total emissions are determined by utilization of
facilities and control technology.
•NOx emissions fall by over 50% due to smart burn
technology at Colstrip coal fired facility,
•VOC emission rise is due to increased plant
utilization and new testing at the Kettle Falls
Biomass facility,
34
-75%
-50%
-25%
0%
25%
50%CO2 SO2 NOx Hg VOC
Total Change in Air Emissions Since 2015
Greenhouse Gas Emissions Forecast
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 681 of 1105
Natural Gas Breakout Room
Tom Pardee
Michael Whitby
Jody Morehouse
EnvironmentReliability
Affordability
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 682 of 1105
Carbon Reduction
Pathways
Power to Gas with Hydrogen
•Renewable electricity converts water to hydrogen
•Hydrogen is combined with waste CO2 to make RNG
•RNG flows through existing natural gas pipelines to
end users
Renewable Natural
Gas (RNG)
•Biogas from
decomposing waste
streams is captured
•The gas is scrubbed to
pipeline quality RNG
•RNG flows through
existing natural gas
pipelines to end users
36
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 683 of 1105
Natural Gas is Critical to a
Clean Energy Future
•In the right applications, direct use of natural gas is best use
•Natural gas generation provides critical capacity as renewables expand until utility-scale
storage is cost effective and reliable
•Full electrification can lead to unintended consequences:
•Creates new generation needs that can increase carbon emissions
•Drives new investment in electric distribution infrastructure, causing bill pressure
•Home and business conversion costs borne by customers
•Puts at risk energy reliability and resilience, energy choice, and affordability
•Customers have paid for a vast pipeline infrastructure that can utilized for a cleaner future by
transitioning the fuel and keeping the pipe
•A comprehensive view of the energy ecosystem leads to a diversified approach to
energy supply that includes natural gas
37
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 684 of 1105

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 685 of 1105

2021 Electric Integrated
Resource Plan

Appendix B – 2021 Electric IRP
Work Plan

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 686 of 1105

Work Plan for Avista’s
2021 Electric Integrated Resource Plan

For the
Washington Utilities and Transportation Commission & Idaho Public Utility Commission

April 1, 2020

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 687 of 1105
2021 Electric Integrated Resource Planning (IRP) Work Plan
This Work Plan is submitted in compliance with the Washington Utilities and Transportation
Commission’s Integrated Resource Planning (IRP) rules (WAC 480-100-238). It outlines the
process Avista will follow to develop its 2021 Electric IRP for filing with the Washington and
Idaho Commissions by April 1, 2021. Avista uses a public process to solicit technical expertise
and feedback throughout the development of the IRP through a series of Technical Advisory
Committee (TAC) meetings and uses a combination of social media and public outreach event to
include the general public.

The 2021 IRP process will be similar to those used to produce the previous IRPs, but with changes
to better align assumptions with the Natural Gas IRP. Exhibit 1 shows the planned 2021 IRP
timeline for work products. Avista plans to use Aurora for electric market price forecasting,
resource valuation and for conducting Monte-Carlo style risk analyses of the electric marketplace.
Aurora modeling results will be used to select the Preferred Resource Strategy (PRS) and
alternative scenario portfolios using Avista’s proprietary PRiSM model. This tool fills future
capacity and energy (physical/renewable) deficits using an efficient frontier approach to evaluate
quantitative portfolio risk versus portfolio cost while accounting for environmental laws and
regulations. Qualitative risk evaluations involve separate analyses. Avista plans to utilize its
proprietary Avista Decision Support System (ADSS) model to conduct analyses to evaluate
reserve products such as ancillary services and intermittent generation. Avista also plans to use its
Avista Reliability Assessment Model (ARAM) to validate resource adequacy and resource peak
contributions (ELCC) as introduced in the 2020 IRP. Avista contracted with Applied Energy
Group (AEG) to conduct energy efficiency and demand response potential studies.

Avista intends to use both detailed site-specific and generic resource assumptions in development
of the 2021 IRP. The assumptions will utilize Avista’s research of similar generating technologies,
engineering studies, and the Northwest Power and Conservation Council’s studies. Avista will rely
publically available data to the maximum extent possible and provide its cost and operating
characteristic assumptions publically. The IRP may model certain resources as Power Purchase Agreements (PPA) rather than Company owned because these third party provided resources are more likely to be lower cost. Avista intends to create a PRS using market and policy assumptions based on the results of newly implemented rules from the Clean Energy Transformation Act (CETA) for Washington and using the least cost planning methodology in Idaho. The plan will also include sections outlining the key components of the Washington Clean Energy Action Plan and an Idaho Preferred Resource Strategy. The IRP will include a limited number of scenarios to address alternative futures in the electric market and public policy. TAC meetings help determine the underlying assumptions used in the IRP including market scenarios and portfolio studies. Although, Avista will also engage the general public using social media and a public outreach event. The IRP process is very technical and data intensive; public comments are welcome and we encourage timely input and participation for inclusion into the process so the plan can be submitted according to the proposed schedule in this Work Plan. Avista will make all data available to the public except where it contains market intelligence or proprietary information. The planned schedule for this data is shown in Exhibit 2.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 688 of 1105
Avista intends to release data prior to its discussion at its Technical Advisory Committee Meetings
and expects any comments within two weeks after the meeting.

The following topics and meeting times may change depending on the availability of presenters
and requests for additional topics from the TAC members. This shortened IRP cycle will only
include five public meetings. The timeline and proposed agenda items for TAC meetings follows:

• TAC 1: Thursday, June 18, 2020: o TAC meeting expectations and IRP process overview, o Review of 2020 IRP Idaho acknowledgement, o Update on CETA rulemaking process, o Modeling process overview, including Aurora, ARAM, ADSS, PRiSM, and assumption overview, o Generation options (cost, assumptions, ELCC), o Highly impacted community discussion (WA- CETA).
• TAC 2: Thursday, August 6, 2020 (joint with Natural Gas IRP TAC): o Demand and economic forecast, o Conservation Potential Assessment (AEG), o Demand Response Potential Assessment (AEG), o Natural gas market overview and price forecast,
o Regional energy policy update,
o Gas/Electric coordinated studies,
o Highly impacted community proposals.

• TAC 3: Tuesday, September 29, 2020: o IRP Transmission planning studies,
o Distribution planning within the IRP,
o Discuss market and portfolio scenarios,
o Existing resource overview,
o Electric market forecast and scenarios.

• TAC 4: Tuesday, November 17, 2020: o Final resource needs assessment and resource adequacy, o Ancillary services and intermittent generation analysis, o Review draft resource plans for each state and scenarios.
• TAC 5: Thursday, January 21, 2021: o Review draft IRP, o Final state resource plans and scenarios, o Draft Clean Energy Implementation Discussion,
o 2021 IRP Action Items,
o Initial comments from TAC participants.

• Public Outreach Meeting, February X, 2021
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 689 of 1105
2021 Electric IRP Draft Outline

This section provides a draft outline of the expected major sections in the 2021 Electric IRP.
This outline may change based on IRP study results, CETA rulemaking, and input from the
TAC.

1. Executive Summary 2. Introduction, Stakeholder Involvement, and Process Changes 3. Economic and Load Forecast a. Economic Conditions
b. Avista Energy & Peak Load Forecasts
c. Load Forecast Scenarios
4. Existing Supply Resources a. Avista Resources b. Contractual Resources and Obligations 5. Energy Efficiency Potential Study 6. Demand Response Potential Study 7. Long-Term Position a. Reliability Planning
b. Resource Requirements
c. Reserves and Flexibility Assessment
8. Transmission Planning a. Overview of Avista’s Transmission System b. Future Upgrades and Interconnections c. Transmission Construction Costs and Integration d. Merchant Transmission Plan 9. Distribution Planning a. Overview of Avista’s Distribution System
b. Future Upgrades and Interconnections
10. Supply Side Resource Options
a. New Resource Options b. Avista Plant Upgrades 11. Market Analysis a. Wholesale Natural Gas Market Price Forecast b. Wholesale Electric Market Price Forecast c. Scenario Analysis 12. Washington- Clean Energy Action Plan a. Preferred Resource Strategy
b. Highly Impacted Community Analysis
13. Idaho- Preferred Resource Strategy
a. Preferred Resource Strategy 14. Portfolio Scenarios a. Resource Selection Process b. Efficient Frontier Analysis a. Portfolio Scenarios b. Resource Avoided Cost
15. Action Plan

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 690 of 1105
Draft IRP will be available to TAC members on January 4, 2021. Comments from TAC
members are expected back to Avista by March 1, 2021. Avista’s IRP team will be available for
conference calls or by email to address comments with individual TAC members or with the entire
group if needed.

Exhibit 1: 2021 Electric IRP Timeline
Task Target Date

Due date for study requests from TAC members August 1, 2020

Writing Tasks
Comments and edits from TAC due March 1, 2021

Exhibit 2: Public Data Release Schedule
Task Targeted Release
Annual Capacity Needs Assessment

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 691 of 1105

2021 Electric Integrated
Resource Plan

Appendix C – Public
Participation Comments

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 692 of 1105
Appendix C:
Public Participation Comments
IRP Comments Provided by Technical Advisory Committee Members

Commenter Comment Avista Response
Conservation
League
1. We request Avista compare the results of this Idaho-
specific study to the results of the same analysis at the system-wide level. 2. We request Avista compare the results of this Idaho-specific study to the results of the same analysis at the system-wide level. 3. We also request a study that documents the costs to implement, monitor and document the state-specific addition of resources to an interconnected system
energy by 2045.
2. Avista split resources and costs between its jurisdictions to understand the effect to each state. 3. All costs to meet resource requirements by state is included in the PRiSM model. The model is publicly available in Appendix I. Also, summary level information is provided in the IRP Chapter 11 and 12.
Conservation League 1. We request Avista study a scenario that applies the Social Cost of Carbon to all resources, including those that serve Idaho, as offered in the first TAC meeting. 2. We request Avista study scenarios for Colstrip costs that reflect the changing ownership shares currently being considered by co-owners Puget Sound Energy, Northwestern Energy, and Talen. Further, we request a
study of likelihood and scale of increases to Avista’s share of common plant costs, remediation costs, and fuel supply costs, including minimum fuel supply and generation off-take, attributable to both the closure of Units 1 and 2 and the changing ownership share of Units 3 and 4. 3. We request a study of the accuracy of Avista wholesale natural gas price forecasting methodology by
comparing forecasted prices in prior IRPs to prices Avista actually paid. We request this study include a comparison of the accuracy of consultant-supplied forecast to publicly-available forecasts covering the
2. Regarding the change in ownership percentages for Units 3 and 4, there are no changes to Avista’s responsibilities or modeling inputs to alter because Avista’s 15 percent share of both units remains static under the Colstrip ownership agreement. Avista’s financial responsibility for the plant remains the same regardless of the non-Avista ownership or ownership percentages for Units 3 and 4. As in the last IRP,
Avista is accounting for the shift (increase) in previously shared costs that are a result of the closure of units 1 and 2. Those costs increased, but Avista’s share of those costs did not change. Avista has zero responsibility for the remediation costs associated with Units 1 and 2. The closure of those units did not end the financial responsibility of those remediation costs for the owners of those units (Puget Sound Energy and Talen). Avista’s fuel contract is separate from the contracts
that supplied Units 1 and 2. Avista’s fuel contract and any subsequent mine remediation costs with our share of coal are already included in the prices being modeled in the 2021 IRP, consistent with past IRPs.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 693 of 1105
3. The natural gas price forecast beyond the shorter term forward markets is always an area of concern because of the potential for volatility, timing and magnitude of outside events,
much like the current pandemic we are now experiencing. It is in our own best interests to use good forecasts. Avista publishes its natural gas price forecasts in each IRP; including both consultant forecasts on an annual average basis. Actual natural gas prices are also publicly available. The consultants
that we use work on a national as well as an international basis. They already perform their own internal analyses to make their forecasts as accurate as possible to maintain and
grow their business. We are paying for their expertise and research into the natural gas market. Avista has not seen any evidence indicating that there are better forecasts available and we do not possess the resources to develop comprehensive fundamentals based natural gas forecast on
our own. Some forecasts, like those provided by the Energy Information Administration, supply some more details about the fundamentals they are using, but they are also more dated and do not provide the level of granularity into specific trading hubs. These consultants would not be able to remain in business if they had to give away all of their research for free. Please let us know if you have found other evidence or research indicating better forecasts. Avista includes the
natural gas prices used in the forecast in Appendix I.
Idaho Conservation League
Storage 1. We request Avista model loads and generation at the sub-hourly level. We recognize Avista began pursuing sub-hourly modeling in the 2017 IRP and further refined the ADSS system in the 2019 IRP. We request Avista fully implement sub-hourly modeling for all IRP studies and processes. 2. We request Avista study the optimal pairing of
generation resources with storage of different technologies and lengths of supplying services. For example: pairing local solar or wind with Li-Ion 4hr, 6hr, and 12hr batteries; pairing pump hydro resources with regional solar, wind, and wholesale markets; pairing long term storage like hydrogen electrolysis and
complexity and data availability. Further, modeling all sub-hourly periods is not technologically possible. Presently, modeling at one-hour granularity requires thousands of hours of computer processing time. Moving to intra-hour modeling would cause an exponential increase in solution time even if the data was available. ADSS and other modeling techniques are used to evaluate intra-hour values, and generally rely on
sampling of relevant time periods. This is specifically the case with the complexity of modeling storage resources. Avista is working on this issue and is hopeful it will be available in future IRPs and will be added as an Action Item in the 2021 IRP if not completed for this plan. 2. As described in the first TAC meeting and distributed to the
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 694 of 1105
associated hydrogen storage with Avista’s own resources and wholesale market generation.” 3. We request Avista study the emission reductions
possible from pairing storage with specific clean generation options along with the Proposal presented to the TAC to apply the average emissions rate of the region for storage paired to generic wholesale market resources.
and combined renewables plus storage options. The options being modeled include distribution scale 6-hour Lithium-ion; 4-
, 8- and 16-hour Lithium-ion; 4-hour Vanadium flow, 4-hour Zinc Bromide flow batteries; 16-hour 100 MW share pumped storage; and 100 MW solar photovoltaic with Lithium-Ion batteries. Avista is also modeling hydrogen using fuel cells or converted combustion turbines. Each of the hydrogen options
will include long duration storage facilities as a backup to real-time deliveries. Avista’s IRP modeling includes the benefits from a portfolio optimization in its current process between
storage and renewable resources. Avista acknowledges there could be a benefit to pairing storage with renewables from a transmission perspective. The economic estimates of the IRP are exclusive of T&D
investments. Although the locational benefits of storage paired with resources may not be optimal when considering other “better” locations to locate the storage. Avista agrees with this concept and is trying to determine the best methodology to model these potential benefits, but the modeling of this concept may not be available in time for this IRP. It will be added as an Action Item if we are not able to develop the concept and include it in the 2021 IRP.
3. Avista includes regional emissions for storage not connected to a facility; for paired resources, Avista does not include the emissions when using the paired resources. Although, over time as paired solar/storage resources are no longer obligated to use the paired resources storage technology to satisfy tax credit requirements will likely use a combined grid/local power for optimization of the system. [Avista’s PRS did not include
storage emissions, but scenarios were conducted to
Conservation League 1. To help encourage the optimal growth of DERs on the Avista system, we request a Hosting Capacity Analysis. This analysis could support a distributed energy resource interconnection map that identifies where
on a public process for this type of planning. This process will likely be separate from the IRP process, but will inform the IRP. More details of this process and its findings will be shared with the TAC as they develop.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 695 of 1105
where the distribution system is constrained and could benefit from energy storage or specific demand responses. This Hosting Capacity Analysis would
benefit the IRP’s load forecasting and overall integration of distributed energy within the IRP. We recommend Avista define DERs broadly for this study to include: customer-sited generation and storage, utility-sited generation and storage at substations or
other locations on the distribution grid, as well as public and private electric vehicle charging stations.” 2.We request Avista incorporate different load shapes
that are indicative of customer generated power as wellas the charging of electric vehicles to ensure accuracyin the load shapes for supply-side resource planning.The Smart Electric Power Alliance has an informativeset of resources to help with this effort:
https://sepapower.org/knowledge/proposing-a-new-distribution-system-planning-model/.”
2.Avista welcomes the information, but at this time is using datacollected from its local system for both solar photovoltaics andelectric vehicles.
Idaho Conservation
League
Flexibility Issues 1.With the technological changes of a modern grid
system, including flexibility in both supply and demandstudies is essential as we look to the future of electricservice areas. As shown in the pilot program with the Catalyst Building, the savings from energy efficiencyand flexible building loads can be extremely beneficial
for the electric grid as a whole. Similarly, the micro-transaction grid project in the Spokane UniversityDistrict is demonstrating the value of flexible loads andnew market opportunities for customers to manage theirpower bills. To fully explore the value that flexibilitybrings to Idaho customers, we request Avista study thepotential to expand similar projects in the Idaho serviceterritory. At minimum, a study to see the perspective of
customers’ willingness to participate in such a pilot program could have lasting results.
1.Avista appreciates the comment to also consider Idaho as atest bed for future projects and will take this under
advisement. Avista utilizes the University of Idaho for severalR&D efforts through a competitive grant process for a total of$270,000 to study efforts related to energy efficiency andflexible building loads. Example projects from the 2019/20academic year include: a program design for energy trading
system for consumers, using infrared cameras for buildingcontrols and gamification of energy use.
Idaho Conservation League
Climate Change Impacts to Avista’s System and Costs 1. Loads - study changes to both long-term load forecastand the peak load forecast attributable to climatechange. The 2020 IRP mentions a 1-degree increase intemperatures, but does not appear to describe how
1.Climate change is being included in the load forecast as ascenario, which was covered in the special TAC meeting onAugust 8, 2020 after receiving this letter. Further, all loadforecast scenario data is available on the IRP website(Appendix I). Please let us know if you have any additional
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 696 of 1105
climate change is factored into the peak load forecast. The 2020 IRP also cites a temperature data set from 2013, which we recommend Avista update to the most
currently available set. 2. Hydro - study the potential changes to hydroelectric power generation that could result from climate-caused changes to precipitation type and timing. This study should document the range of impacts to power costs
that result from the changes in hydroelectric power generation. 3. Thermal plants - study potential changes to expected
generation and production costs due to temperature changes. This study should include changes to expected generation and fuel costs as output varies with ambient temperatures and the impacts to cooling water needs due to changes in precipitation and water
temperatures. The study should document the range of impacts to power costs due to the change in expected generation output, fuel needs, and cooling water
presentation. 2. We have obtained the climate adjustments developed by the
Power Council and included a scenario with these adjustments in Chapter 12. 3. Avista agrees temperature changes will impact the amount of production from its natural gas-fired facilities. This impact will was included in the climate change scenario.
Conservation League 1. The load forecast includes the baseline projection of electric charging services, as forecasted in the 2020 TEP. We also request scenarios that consider higher penetration of EV, especially for commercial fleets,
delivery vehicles, and public transportation. 2. A study of how to optimize charging behaviors, including customer load management, and how to optimize the location of public and workplace charging stations to avoid distribution grid overload while maximizing grid flexibility and benefits to the system. For example, the TEP identified that the $1,206 in electric system benefits per EV could “be increased by
another $463 per EV when load management shifts
this time, Avista needs to focus on other scenarios for this IRP because of the limited amount of time available for modeling. 2. Avista is updating its EV and demand response program assumptions and this will be discussed at the September TAC
meeting. Avista welcomes this discussion at the upcoming meeting to ensure it has robust assumptions for this IRP.
Solutions ductless heat pumps and water heater heat pumps. This is in regards to the electrification scenarios. See attached letter in Appendix C- “Climate Solutions- Electrification End
Further detail regarding these comments are included in Appendix C- “Climate Solutions Email Response.pdf”
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 697 of 1105
Northwest Power & Conservation
Council
Preliminary market price forecasts for the 2021 Power Plan diverge from the pricing regime shown in this draft IRP. While understanding the underlying cause of that
divergence would take a deep dive into our respective AURORA runs, given our work thus far we would expect that it’s related to allowing AURORA to construct new natural gas generation outside the Northwest to replace expected retirements in the WECC thermal generation fleet
(and the associated volume of those retirements). We were given guidance from the Council and from our
advisory committees to limit the potential for new natural gas generation both inside and outside the region. In doing so, we see a wave of solar and wind generation construction that depresses future market prices substantially lowering them from prices seen today. While
this is largely outside of the control of the region, it presents substantial risk to regional utilities making decisions consistent with market prices that assume natural gas resources will set the marginal price. We’d encourage all the utilities in the Northwest, including Avista, to test any IRP-based decisions against an aggressively low market price forecast. Many things are
uncertain about the future of the power system in the WECC. We would not want to represent any forecast, including our own, as certain. But we do think it’s a risk to consider and one that will be developing rapidly over the next few years. While we’re still working on the 2021 Power Plan, we’d be happy to share an AURORA archive file of the work done to
date.
extremely volatile, more than Aurora can quantify, much of this volatility will depend on how much and whether capacity resources
will be developed or not. It is appropriate to understand the risk of higher and lower prices. From analysis in the short term, Avista’s price forecasts are too low- specifically not including risk premiums we are seeing from resource adequacy issues we are seeing. Although, in the long run there is significant downward risk with
more renewables- The future will depend on how far policy makers will take goals and ambitions to actual operations and construction.
There will also likely be a feedback loop as well- such as changes in loads (both industrial losses and electrification opportunities and political changes due to ramifications of policy changes) and storage opportunities. Its possible storage could be key in keeping
prices from getting too low- but that will depend on future costs of that technology. In the end there is a number of paths the future may take us and its really an issue of how much time should we make to look at the region versus our portfolio. The way things are trending there should be more focus toward our portfolio then market prices. In this case the real risk of having too low of forecast for prices
could have an effect of less acquisition of EE, but in the end with our requirements of having clean energy and capacity- the price forecast really only impacts a solar vs wind decision- but so far wind is winning that decision due to capacity requirements and over reliance of solar elsewhere; then they question of should we build natural gas or storage- that decision is likely a matter of carbon pricing at this point. So where I’m going is and have been pondering for some time do price forecasts really matter for
resource planning- given we have fewer resources to choose from and specific requirements to meet. For example, the energy price used to be a major component of our EE avoided cost- now the highest component is social cost of carbon and non-energy benefits- its seems the world has shifted from energy price
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 698 of 1105
Conservation Council Electric IRP_councilstaff.pdf” Most comments were regarding providing additional context for statements Rye Seek further information regarding modeling and assumptions for pumped storage
o “State of Charge” assumed (table 9.12)?
 Table 9.12 indicates an 8-hour pumped storage project would only contribute 30% to Avista’s
peak capacity need and a 12-hur project would contribute 58%. These are much lower than Swan Lake and Goldendale would expect and
drastically lower than those used by other NW utilities
 Swan Lake and Goldendale believe Avista is
using a very low state of charge possibly 20% pond fill). This doesn’t align with the operational realities associated with operating
hydro or pumped storage facilities.
 Import assumptions during off-peak hours in the winter should be re-visted, given that these
would be key hours when long-duration storage would charge for the winter on-peak reliability
 Swan Lake and Goldendale recommend that
Avista consider optimizing the dispatch of their resource over a wide time window (1-2 weeks) allowing for greater flexibility and minimizing
the need for daily charging/recharging o What duration of useful life? o
2021 to discuss their comments
• Avista modelled several northwest pumped hydro projects
in the 2021 IRP; including Swan Lake and Goldendale, based on publicly available data. Avista believes some of these comments could be derived from the 2020 IRP. • Avista acknowledges Rye’s comment regarding re-
charging capacity during off-peak hours. Avista disagrees
with Rye that it can fully recharge a storage devise during off-peak hours of a northwest system peak event beyond the limits already included. • Pumped hydro is optimized on a 1 year basis and not 1 to
2 weeks. • Avista uses a 50-year life to amortize capital costs.

• Given the state of Washington policy, Swan Lake and Goldendale request that Avista provide a detailed
explanation for why a new gas resource would meet
one of the few and limited CETA provisions allowing
construction of such resources, particularly including
violation of reliability standards and, if violations are
possible, whether pumped storage could help alleviate
Goldendale in its PRiSM model. Given information available, these projects were not cost effective compared to natural gas. Avista’s IRP is an indication of cost-effective resources, but a future
request for proposals (RFP) will determine the most cost-effective resource acquisition.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 699 of 1105
Rye Advocate that Avista issue a capacity RFP (strongly support)
• Swan Lake is expected to achieve commercial
operation in late-2026
• Only accurate way for Avista to fully evaluate potential pumped storage projects including various pricing
information, timing for construction and whether the
need.
Northwest levelized cost ($/kW) for the preferred 4-hour lithium-ion battery, as there appears to be a gradual price increase after 2033 rather than a steady decline, which would be expected.
renewable RFP. Further, Avista also used publicly available studies for its future cost curves. One difference between our forecasted cost could be they are in nominal dollars rather than “real” dollars. Avista’s storage costs are expected to decline significantly in “real” terms. Avista also recommends any
suggestions regarding costs of resources come earlier in the process. Avista included these costs in its TAC meetings and posted all its cost information on its website six months prior to the
Northwest generation on a sub-hourly timescale to calculate the
balancing reserve requirements and the associated system costs and benefits to meet those intra-hourly dispatch requirements, as legally enforced through NERC’s BAL
ancillary services costs using its ADSS system. This process will
begin in 2021 Q2. Also Avista is considering Plexos for potential reliability studies and other work, but has not acquired the model at this time.
Northwest operational configurations and characteristics of hybrid resources and standalone storage to correctly evaluate the resource ELCC value.

next. Avista disagrees with using alterative ELCC values for storage resources based on its analysis of its system. Specifically, Avista is concerned with relying on short duration storage in winter months because of its high winter energy needs, lack of reliable
market power in critical events for recharging the system, and high
Northwest why Avista’s capacity needs can only be met with new
natural gas peaking capacity, we recommend that Avista provide at its upcoming TAC meeting or publish in its final IRP a projected loss-of-load event, displaying by hour where there is a deficiency in available capacity. This could
information required to develop the 12x24 matrix. Avista agrees
this could be a useful exercise and will consider developing this report in the next IRP as it continues to review ELCC studies.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 700 of 1105
hours with the highest loss of load probability which were used to calculate the ELCC values for all resources. Renewable Northwest We recommend the Company conduct one additional analysis to better understand how policy-driven changes in
Avista’s resource mix should impact the way the Company plans for meeting demand reliably and at least cost.
Avista agreed to conduct another portfolio scenario named 5B to remove Colstrip in 2022 (just as with the PRS) and follow the other
logical requirements of the Portfolio 5. This portfolio is the 100% clean energy portfolio by 2045.
NW Energy
Coalition
The preferred portfolio continues to develop energy
efficiency and begins to lay out a strategy for acquiring demand response resources, although we believe the targets can be increased and the pace can be accelerated. The treatment of new renewable resources is somewhat more mixed, as described below. Finally,
significant improvement is needed for both the cost and capacity value battery and pumped storage.
Avista future. Avista agrees some programs will take time to ramp up to large savings and some rate restructuring programs will take time to develop and get approval through multi-jurisdictions. Regarding battery & pumped hydro, Avista continues to use the
best information publicly available for these resources. Avista even specifically modeled many of the Northwest proposed projects. Avista also recommends any suggestions regarding costs of resources come earlier in the process. Avista included these costs in its TAC meetings and posted all its cost information on its
Coalition substantial available and cost-effective clean energy resources that can defer or eliminate this new emitting these emerging technologies decline.
Coalition greenhouse gas emissions are considered and priced using the SCC”, but that the SCGHG was not applied to market purchases and sales in the PRS as done previously. The reason for the change from previous practice is not clear.
document. In summary, after consultation with WUTC policy staff, Avista chose not to include the SCGHG/SCC as part of the market transactions specially because the CETA does not require these costs for short term transactions. Avista did conduct a study to see
the implication of the change. Avista will discuss this option again
Coalition natural gas generation, we urge Avista to revisit
this issue and adjust the upstream methane emissions factor represented in the Social Cost of Greenhouse Gas analysis.
approximately 10% of the natural emissions directly burned. By
including these emissions as part of the social cost of carbon exceeds regulatory requirements in Washington. While upstream methane emissions will always have uncertainty due to life expectancy and the variety of sources, Avista will continue to make the best estimates for these emissions given its fuel
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 701 of 1105
portfolio that is better aligned with CETA policy guidance while meeting reliability needs cost-effectively. The first stage involves maximizing the availability of so-called
“energy limited” clean flexible resources, including demand response and storage. These are generally considered to provide capacity value of 4 hours duration and should suffice for meeting needs during typical peak periods. In the second stage, meeting rare long-duration peaks
requires supplemental resources. The draft IRP suggests that new peakers can meet these supplemental needs. But once these very expensive and high-emitting new peakers
are put into the resource mix, the IRP models will dispatch them not only for very infrequent long duration high peaks, but much more often across the year because they are now “existing” resources. As a result, these new peakers will displace less expensive, non-emitting resources. This
creates a lost opportunity for CETA compliant clean energy
Specifically the options to acquire resources for a5 to 10 year period will allow for a staged acquisition of cleaner resources that
may potentially become available in the 2030s. While the IRP does a great job at evaluating new resources this shortcoming means IRPs will always identify a resource mix that may differ from the actual resource acquisitions obtained through an RPF or another competitive bidding process. Avista anticipates
significantly more cost effective cleaner resource options will be available as it acquires new resources.
Coalition for DR at 90 MW in 2025 (about 5.1% of peak load) and
170 MW in 2045 (almost 10% of peak). NWEC agrees that this is a reasonable magnitude for total potential, but we
demand response. Avista modeled these programs to be available
to begin in any year and optimized our system over the full 24 years. Beginning programs earlier will add cost to customers prior
Coalition simply don’t seem reasonable. The values in Figure 9.1 show slight declines in battery costs, and then flat or rising
costs through the remainder of the planning horizon. Most other estimates show consistently declining costs through the coming decades, though at varying rates.
best information publicly available for these resources. Avista even specifically modeled many of the Northwest proposed projects.
Avista also recommends any suggestions regarding costs of resources be submitted to the Company earlier in the process as they’re more likely to be able to be included. Avista included these costs in its TAC meetings and posted all of its cost information on
Coalition reasonable chance of commercial operation by 2027, and found to be cost effective compared with a new natural gas
Coalition encourage revisiting this key issue. Hybrid resources could
provide a significant capacity benefit and defer the need for new gas peakers, as well as make more effective use of limited available transmission capacity for renewables and
conduct further ELCC analysis to ensure proper peak credits of
these resources so Avista customers have a reliable system.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 702 of 1105
WUTC Staff Clean Energy Action Plan • Add a table to the CEAP that includes year-over-year capacity of all planned resources, including demand response. • Include planned Appendix G with details of about
planned transmission and distribution
year transmission plan and its 2019/2020 System Assessment
Climate change • Provide discussion regarding the implications of possibly moving from a winter peaking utility to a analysis in Chapter 3 and Appendix K. Further, Avista modeled a portfolio scenario in Chapter 12, outlining the changes in resource
Load Forecasting • Clarify the date in which its economic inputs were
finalized. • Discuss any adjustments to the forecast made in
response to the ongoing pandemic. • Clarify the high and low load growth ranges used on page 3-14. For example, how did the company
settle on the high and low assumptions for annual service area employment and population growth outlined in table 3.3? Please explain. • Discuss the assumptions behind the EV and solar PV forecasts that are inputs into the load forecast. • Clarify which of the two climate change forecasts
Upstream Emissions & SCGHG • Include in the narrative description required by WAC 480-100-620(11) a clear articulation of how the company calculated the SCGHG. • Discuss assumptions about the SCGHG in market purchases and charging storage resources with
market purchases. • Explain why 1.0 percent is an appropriate upstream
greenhouse gas analysis in chapters 9 & 11. Regarding the upstream emissions, this is in relation to the Natural Gas IRP.
Sub-hourly Modeling Capabilities • Clarify storage cost assumptions.

Chapter 9.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 703 of 1105
WUTC Staff Customer Benefit Provisions in CETA • Provide a scenario or, at minimum, a narrative regarding possible changes to resource decisions that could increase customer benefit. • If available and time permits, incorporate the DOH
maximum customer benefits. Avista is also planning to engage a consultant to help estimate non-energy impacts for further analysis
regarding customer benefits. These changes may be available in the CEIP, but at minimum the 2023 IRP. Unfortunately, the DOH data was not available for the 2021 IRP.
Resource Adequacy and Uncertainty • Clarify the company’s peak credit methodology, including the definition of “peak” terms. • Explain how the company incorporates uncertainty
Chapter 9. Regarding the uncertainty of the RA assessment, Avista added information in Chapter 7 using the risk topic discussed in the “Implications of regional resource adequacy
Public Participation
• Provide an IRP update based on any recent
planned resource acquisition.
complete in time for the 2021 IRP. Avista plans to update the WUTC with a new Clean Energy Action Plan if any contracts are
Data Disclosure • Ensure appendices include a record of stakeholder feedback and the company’s response. • Provide context for the data files provided on the
comments from TAC members as well as Q&A and comments from the Company’s Public IRP meeting.
Natural Gas Design Day (Planning Standard) • Explain the new design day methodology. • Explain why the new design day standard is now
Renewable Natural Gas • Include details of RNG cost assumptions in the
scenario included in the 2021 draft IRP. Why the change
from last year?
Avista included the Lancaster PPA extension analysis in the 2020 IRP based on a request by the Idaho Commission staff. For the
2021 IRP, no such request was made until now, so it was not included as a scenario. Given we do not have a firm price for a PPA extension, or any other existing resource, we don’t think it would be appropriate to include it in the public IRP. One of my concerns with IRPs, is it is predominantly based on acquiring new resources and often does not or cannot do a good job of illustrating resource choices when existing resources are available. The IRP shows the resource options for new resource
choices and does a relatively poor job at studying existing
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 704 of 1105
the end, the IRP is a way to calculate the avoided cost of new generation or demand-side resources. The plan showing a need for new natural gas CTs does not preclude us from acquiring a
different resource that is a better solution for customers through an RFP or another acquisition strategy. We have recognized our IRP analysis needs to improve how we review existing resource options and that has been identified as an Action Item for the next IRP to determine the best way to include the potential to extend
existing contracts in the IRP.
Tyre Energy Would you consider revising this draft to include a 10 year Lancaster PPA extension scenario? It seems unlikely to us that choosing not to extend the Lancaster PPA and turning
around to immediately add 210+ MW of new peaking capacity in 2027 would be economically advantageous enough (compared to a Lancaster PPA extension scenario) to exclude the extension scenario from the IRP.
Avista believes the IRP illustrates the need for firm capacity, it shows natural gas is a viable option. The decision for an existing plant vs a new facility or any other option is best decided in an
RFP rather than an IRP. In the future, if Lancaster should be considered in the IRP, Tyre should provide the IRP team with firm pricing for the resource option.
Tyre Energy Will you share with us the unit parameters for Lancaster that would be used for a Lancaster PPA extension
scenario? We’d like to understand what level of operational flexibility would be assumed in a Lancaster PPA extension scenario.
Avista would like to understand your options to improve flexibility of the machine. As you know we are transitioning to more
intermittent resources will require us to have more ramping and start/stop requirements.
Dave Van
Hersett
Biomass generation option should be included as one of the
alternatives evaluated to determine relative economics of the three approved new generation types, wind, solar and biomass here in the Inland Empire. We have the moral obligation to utilize the forests for the benefit of mankind not to fuel forest fires to destroy property and kill our neighbors.
Avista included both an upgrade to Kettle Falls and a new biomass
resource option in the IRP. The KF upgrade was selected in the PRS, a new facility was not cost effective in the PRS but will be continued to be modelled as an option.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 705 of 1105
Avista’s Integrate Resource Plan Public Meeting
February 24, 2021

These are results of the poll questions given to the audiences in both the webinar and breakout
rooms sessions.

Webinar Poll Questions
1. What would you prioritize among the choices below, acknowledging they are all important? • Environmental Issues: 32 • A Reliable System: 75 • Affordability: 33
2. Which Avista system provides more energy to its customers?
• Natural gas: 66 (this answer is most correct)
• Electric: 69
3. If Avista were to offer a voluntary program to charge higher prices during 4:00 pm to 8:00 pm in exchange for lower prices in other hours would you be interested? • Yes: 77
• No: 59
Generation and Reliability Breakout Room
1. When Avista acquires new generation resources- where should they be located? • Indifferent to where resources are located: 6 • All of the above: 26 • Within our local communities: 9
• Within our service territory, but not in our local communities: 6
• Outside the service territory (i.e. another state or Canada): 1
2. To meet reliability needs in the next 5 years, how should Avista meet this requirement
• Acquire natural gas generation with a modest environmental footprint- medium cost
alternative: 33
• Acquire storage resource with low operational environmental footprint- highest cost
alternative: 11
• Utilize customer outages to stabilize the grid- lowest cost alternative: 2
Affordability & Equity Breakout Room
1. How much of your electric bill should go towards assisting or improving the lives of
individuals and communities who are economically disadvantaged?
• $0 per month: 6
• $5 per month: 9
• $10 per month: 6
• Other: 4

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 706 of 1105
2. What does an equitable transition to clean energy mean to you?
• Lowering their energy rates: 9
• Making their homes more energy efficient: 12
• Build clean generation resources within their community: 3
• Beautification of Avista assets: 1
• Other: 1
Natural Gas System Planning Breakout Room
1. If you could no longer use natural gas, which fuel would you likely use in its place?
• Electricity: 12
• Hydrogen: 2
• Propane: 8
• Renewable Natural Gas: 6
• Wood: 6
• Other: 3

Environmental Breakout Room
1. How should Avista best balance customer costs and environmental stewardship?
• Do the minimum to meet environmental requirements and keep energy rates as low as possible: 1
• Be a partner and leader in environmental stewardship for a mod rate increase: 5
• Marginally exceed requirements for a small rate increase: 1
• Make environmental improvements and reduce impacts no matter the cost: 1
2. What is the most important environmental issue for you related to Avista?
• Reducing greenhouse gas emissions: 1
• Minimizing air pollutants such as particulate matter, volatile organics and nitrous/sulfur
dioxides: 3
• Being stewards of the water and natural resources of the Clark Fork and Spokane Rivers: 4

Energy Efficiency Breakout Room
1. In exchange for slightly lower energy costs, are you are interested in the utility controlling your thermostat?
• Never: 9
• No more than 20 hours per year: 1
• Yes, if I can override the request if I’m too cold or hot: 18
2. What is most important to you when you invest in energy efficiency for your home?
• Increase comfort: 4
• Reduce emissions: 4
• Savings on your bill: 20

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 707 of 1105
Questions from emails, breakout sessions, and chat box
For those of us who have solar panels on our roofs and are producing more
electricity than we use, what plans do you have to compensate us for our excess electricity?
kilowatt hour (kWh) compensation for their
generation. Generation produced by customers in excess of consumption is held in a ‘bank’, allowing kWh credit to be used in future months as needed. The intent of net metering is to offset your own usage, based on this intent any remaining kilowatt hour bank is reset
annually in March, according to Schedule 095 in both Washington and Idaho. There are no current plans under the net metering program to provide compensation beyond the banking provision. Please reference Schedule 095 in both Washington and Idaho for further details.
Electric Vehicle Questions Avista Response
plug-in vehicles (hybrid and pure electric)? publicly available at: www.myavista.com/transportation This plan includes Low, Baseline and High adoptions
scenarios for light-duty vehicles considered in Appendix B. starting on p. 81. Given the current state of policy support,
industry investments, utility support, and local geographic and demographic considerations; we expect the trajectory of
adoption to track between the medium and high scenarios in
Washington, and between the baseline and low scenarios in
charging at preferred times of the day, when other demand is less? Plan, Avista has shown that utility programs leveraging EVSE
installations can accomplish this with participating customers. A new rate incenting off-peak charging may also be very effective, as demonstrated in other utility pilots and
studies. Avista will continue to develop capabilities, with a goal to shift 50% or more of EV peak loads to off-peak in a cost-
more places to charge such vehicles, like in high use areas (central parking lots, shopping malls, park-and-ride lots)?
charging infrastructure, up to 50% of the assessed market
need. A variety of other programs and incentives including “make ready” investments, and a new commercial EV rate, will help encourage additional private investment. See the TE
emissions, is there a plan to convert and cost effectively. See TE Plan pp. 72-73.
cars been added to the percent of
emissions as a long term cost? shown in the TE plan on pages 41-42, based on Avista’s generation mix. Likely emissions in the future based on effects
from battery waste and other factors are very uncertain but
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 708 of 1105
knowledge and certainty is gained. See TE Plan pp. 22-24 for discussion related to battery research and development,
including second-use and recycling. The future state of battery technology and production will most likely differ greatly from the current state.
What does your company anticipate the impact to be from the forthcoming increase in electric vehicles and how will you
prepare for that?
Avista expects a 39 aMW increase in residential load from electric vehicles by 2045. The Company prepares for changed in forecasted load through this biennial resource
planning process and issue RFPs for various resources as needs arise.
Policy Questions Avista Response Why doesn't AVISTA push back against Washington State's population-reducing polices? What plans do you have if the population is killed by lack of heat?
Avista isn’t aware of any legislation that is specifically and explicitly intended to reduce population. Our engagement in
public policy is first and foremost focused on the cost-effective
operation of our energy system and the economic vitality of
the communities we serve.
Avista has an obligation to serve its customers electric and natural gas demands. When developing its resource plan, it
determines the expected customer demand and the amount of resources and types of resources that can actually meet this target using standard utility practices. Avista plans for resources to meet a 1-in-20 standard. This means it has enough resources to meet all customer load in 19 of 20 possible extreme weather events.
eliminate natural gas in new residential and commercial buildings by 2030 and to replace gas by heat pumps. At colder temps, heat pumps stop producing heat efficiently and can cause a spike in demand. Your presentation includes
customer choice for residential heating. Avista agrees that electric heat pumps lose their efficiency at lower temperatures and an “electrification” policy that requires customers to convert their natural gas heating systems to electric heat pumps will increase electric peak loads, among other impacts.
businesses, the main targets of efficiency efforts, will the harsh legislative regs. drive commercial and industrial businesses our of our region? Result, loss of jobs as well as revenue losses?
viability of businesses and shares the concern that such
policies will have dislocation impacts on business and workers. Avista’s energy efficiency analysis shows commercial and industrial businesses have opportunities to save energy
economically while maintaining current requirements by
installing more efficient technology. Avista’s energy efficiency programs will assist these customers with cost effective financial incentives. Lastly, the expected energy cost savings
Environmental Avista Response
natural gas companies that use fracking and other means to obtain natural gas? is delivered through the pipeline system. Natural gas from all sources is mixed together, and gas from wells that used fracking technology makes up the majority of natural gas currently. The environmental issues associated with drilling for
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 709 of 1105
federal laws and regulation, which have increasingly been focused on the fracking process. Avista carefully manages natural gas once we receive it from pipelines. We were a founding member of the EPA’s methane challenge in demonstrating our leak detection and
maintenance efforts. In addition, natural gas producers are increasing efforts to reduce emissions of natural gas
production and make this energy source more sustainable. See https://www.aga.org/natural-gas/clean-
technology to create a carbon free source of power, electricity?
What about Gen IV Nuclear? Is there any movement toward building these very
IRP analysis to determine if any specific offerings fit our resource needs. Currently Avista finds this technology not to be cost effective. Like others, we are watching to see how new
emerging nuclear technology performs and how the cost changes as the technology develops.
align/don't align with Inslee? In particular, the use of natural gas, which I understand Inslee wants to limit or get rid of entirely.
part of the Washington State legislative landscape. We continue to engage in legislative settings to promote clean energy solutions that are affordable and which support reliability for our customers. Regarding natural gas, a specific bill was introduced during the 2021 legislative session. While this bill has not advanced, we will continue to work with our legislators and regulators on ways to address emissions
as machinery and maintenance cost) is there on the act of compressing natural
gas?
compressor to less than 1% of the original volume. While energy is needed for such compression and there are
emissions associated with the compression process, the net effect of using CNG as a transportation fuel is reduced emissions. All fuel delivery systems, including CNG, include ongoing maintenance costs for machinery.
that it is my understanding, backs up the intermittent power from wind farms like the one in Pullman? Is it really that "dirty"? If
the tribes don't want to run it, can't Avista lease it? Can you build a new state of the art coal plant? Coal presently provides over 60% of all
electricity in the U.S. Our plans are super scrubbing in the U.S.!!
Washington State law prohibits the delivery of coal-fired energy to customers after 2025. Colstrip is also subject to other state and federal environmental regulations, which
continue to evolve. As one of six owners of the plant, Avista cannot independently determine Colstrip’s future. We will continue to evaluate the role that Colstrip plays in meeting our customers’ energy needs, and also how Colstrip’s future impacts communities, including Tribes, in Montana. We rely
on thermal generation from Colstrip, natural gas-fired plants, and our biomass plant in Kettle Falls, along with our significant hydro resources, to back up intermittent renewables. Consideration of this need is one of the key
consider methane emissions? are working to reduce emissions associated with natural gas
and developing additional strategies with that in mind. Our natural gas IRP discusses the current state of these efforts,
which we expect to build on and communicate further. Also
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 710 of 1105
estimates for the methane emissions as part of the upstream emissions from fuel suppliers and transporters.
Could you still sell coal energy in Idaho? Yes. Currently there are no prohibitions currently in Idaho for serving our customers with coal-fired electricity.
Are there perceived or anticipated issues with relicensing the existing dams in the network?
Avista relicensed our Clark Fork hydro project (two dams) in 1999, receiving a license from FERC for 45 years. We relicensed the Spokane River hydro project in 2009, receiving a 50-year license. While we don’t have “relicensing” issues, we are implementing agreements with numerous local, state, federal and tribal partners on both river systems. These collaborative efforts imbed flexibility in what specific projects we undertake, for the benefit of our customers and the natural resources associated with these rivers. Please see
https://www.myavista.com/about-us/celebrate-our-rivers for
Methane, the primary component of natural gas, for the first 5-10 years is 100 times the greenhouse gas potential of CO2.
Gas Emissions is mostly from changes away from coal?
Yes, Avista’s forecasted reduction in greenhouse gas will be primarily from exiting the Colstrip Coal plant. The second largest reduction could be utilizing other resources rather the buying power from the Lancaster Generation Station that uses

for solar or geothermal heat pumps. Plans
to send out pamphlets, for swamp coolers, on demand water heaters, or ways to transition to higher demand.
energy use. We work with developers regarding solar for
residential and industrial plans in various ways. The IRP includes some of those plans. In the IRP, we look to fill resource needs by reviewing available options for new energy efficiency and demand response programs. Our energy efficiency team looks at developing programs based on the
results of those plans. We are also adding another advisory group in Washington to reach out to communities for input about ways we can be most helpful to them within the next year. Some incentive programs are prescriptive, like lighting, while others are customer specific and require working with engineers to implement (usually for commercial and industrial customers). We have information on our website for programs for energy efficiency as well as placing solar on homes. There’s a solar evaluation estimator tool that will provide solar potential for specific addresses in our service territory.
the low Snake River have on electric resources?
Avista does not purchase power from the Snake River Dams. The impact of the current proposal on Avista seems at this time to be indirect. However, its effect on communities served
by the company could be significant. It could also have regional ramifications of clear interest to Avista. Gauging the precise extent and nature of the proposal’s potential implications is difficult without more specific information about replacement generation and other measures (conservation, demand response, transmission upgrades) that the proposal
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 711 of 1105
As a Washington-based company, will they be required to discontinue ownership of Colstrip based on the new laws that are under discussion (should those new laws be passed)?
Avista is required to stop delivering coal power to Washington customers in 2025 per the Clean Energy Transformation Act in 2019. The law does not require us to discontinue ownership of the plant and Avista must make future decisions about the plant in conjunction with the other owners. I'd like to hear about the storage technology for variable renewables. Avista includes many energy storage technologies in its resource planning as options to meet customer demand. These options include lithium-ion, pumped hydro, liquid air, hydrogen, and flow batteries. These technologies may be
pursued in the future if they are an economic method of meeting our customer demand.
Does Avista have plans to address the impacts to fisheries due to the construction
and operation of the hydroelectric facilities? The dams on the Spokane River are initially responsible for the complete
extirpation of salmon in that basin. Avista should have some responsibility for
recovering those runs and the communities that were impacted by their loss.
All of our hydro facilities, including the two dams on the Clark Fork and 6 on the Spokane River. Went through an extensive
licensing process working with local tribes, state and federal agencies, and hundreds of stakeholders ranging from 5 to 7 years to work out the issues involved with the dams. Every
week we work with the numerous tribes regarding the fisheries and bringing the steelhead back up to the upper regions. We
do a lot of work together over those issues.
Solar produces less GHG short term. We do not know the environmental cost of solar waste from worn out panels long term.
This is outside of our required planning but think we will see this issue in upcoming plans regarding total life-cycle costs and the wastes associated with worn out solar panels. Are there any plans to partner with Conmat for renewable natural gas plans? There are opportunities regarding this, but none with Conmat specifically at this time. One path to substantial GHG emissions is the deployment of EVs on a large scale, not only Avista's service fleet but also to private citizens but most of the Northwest doesn't have the EV charging infrastructure to support this market change. Is Avista working to address this because that is a massive increase electric demand?
Avista is committed to the development of EVs in our service area and its own fleet. The IRP includes this additional expected demand as part of our plans, but actual EV adoptions will depend on customer demand. Avista is committed to breaking down barriers to increase its adoption. Please see the EV section of these questions and answers for more details about Avista’s EV plans.
Also, upgrades to street lights to reduce energy consumption? Company-owned streetlights have been switched to LEDs. These 5-year implementation programs started in Washington in 2015 and Idaho in 2016. As an Idaho customer, I am hoping that the stricter laws in Oregon and Washington do not equate to my power needs being met by a higher percentage of coal-based
power. As new laws are passed, and since Avista has a plan to phase out from Colstrip, is it possible to assume that this coal-based power supplier will be closed?
Avista has no plans to increase coal generation as a percentage of Idaho’s energy portfolio at this time. Avista does need to acquire new resources to replace capacity beginning in 2026; it is possible, but highly unlikely coal will be chosen to
meet this need for Idaho customers. This issue will be brought up with the Idaho Public Utility Commission and they will review and approve any plans for phasing out coal power being used to serve Idaho customers with input from customers.
I’d like to hear a report on the “state of the salmon” and an acknowledgement of the successes in increasing salmon runs after hugely costly efforts.
Avista isn’t directly involved with salmon recovery efforts. For a state of the salmon, refer to this federal site https://www.nwcouncil.org/reports/columbia-river-history/planningfishandwildlife. Could Colstrip be leased by Avista and run by the utility if the tribes don't want to do it? Avista is a 15% owner in Colstrip Units 3 & 4, the remaining owners are other utilities and energy companies. Due to
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 712 of 1105
Could a new state of the art back up plant for wind farms and solar, be built at a reasonable cost?
Washington law, coal cannot be used to serve customers after 2025 and new coal is more expensive than other technologies available to serve Idaho customers.
Equity & Affordability Avista Response How does equity play into these decisions? Equity of what? The Clean Energy Transformation Act (CETA) directs utilities to ensure “that all customers are benefitting from the transition to clean energy: Through the equitable distribution of energy and noneenergy benefits.” RCW 19.405.040(8)
“Equitable distribution” means a fair and just, but not necessarily equal, allocation intended to mitigate disparities in benefits and burdens, and based on current conditions, including existing legacy and cumulative impacts, which are
informed by the assessment described in RCW 19.280.030(1)(k) from the most recent integrated resource plan. In accordance with the rules, Avista staff is currently forming an Equity Advisory Group that will advise the utility on equity issues including, but not limited to, vulnerable population designation, equity indicator development, data support and development and recommended approached for the utility’s compliance with WAC 480-100-610 (4)(c)(i). This advisory group will help determine the answer to the equity question
using your profits to pay for these
upgrades?
and to maintain a safe and reliable system. When the
company invests capital in these assets, the State Commissions determine if these expenses are prudent. If they find them prudent, Avista will get recovery of these expenses, if the expense is a capital investment, the company may earn a return on these investments. The Commissions also set the
how will the rate payers be charged for the increased cost on new "green" energy
infrastructure? Will Idaho have to pay for the "green" energy that WA and OR want? Or can you make them pay more for the increase in green that they crave and cost
be reviewed by each state’s regulatory commission. It is expected the costs for state compliance will be borne by the
customers within the state where additional costs are required. Both commissions specifically review rate requests to ensure that customers from their respective state are paying only their fair share.
Equity of what? vulnerable customers are protected and benefit from the
ongoing development of our electric system. This advisory group will also help shape how equity will be incorporated into
Transmission/Distribution Avista Response
distribution/transmission planned for the near future? following website: https://www.oasis.oati.com/avat/index.html.
Major Transmission projects planned for 2021 include:
• Rebuild approximately 13-miles of 115kV Transmission
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 713 of 1105
• Build new approximately 12-miles of 115kV Transmission between our Saddle Mountain and Othello Substations.
• Rebuild approximately 7-miles of 115kV Transmission between Addy (BPA) and our Gifford Substation (1st
Phase of 3-year project in Colville area).
• Rebuild approximately 10-miles of 230kV Transmission between Oxbow (IPC) and our Lolo Substation (1st Phase of multi-phase project).
• Integrate new 115kV Irvin Switching Station in the
Spokane Valley.
• Complete replacement of underground 115kV cables in downtown Spokane.
• Replace approximately 3-miles of 115kV Transmission south of Springdale, WA.
• Many smaller projects across the service territory for both
Transmission and Distribution projects are included in the
power lines? Will it be part of this 20-year plan? tree-related distribution outages, burying distribution lines is not a component of the Resource Plan. For new construction, Avista undergrounds facilities when appropriate. Avista has no systemic plans to underground existing facilities at this
Resource Selection Avista Response
providers and universities to get large federal grants to develop and field test new energy storage systems?
research in storage. Avista has also been a recipient of Washington State grant funding and field tested a vanadium flow battery in Pullman and is currently developing a project in the U-district of Spokane to integrate smart building designs
production builds/upgrades planned for the near future? baseload or 24/7 facilities. Current plans include new peaking resources, renewable resources, energy storage, energy
efficiency and demand response in addition to our current
needs (Rathdrum prairie), and how will it affect the reliability and price of our utilities? How are you dealing with the increase of population (and its need for
requiring service in our service territory, so the electrical and natural gas infrastructure will be built to meet the demand as it develops.
increase in population? Avista’s economist conducts a forecast of future population and energy growth within Avista’s service territory as part of the load forecast. This forecast is updated each year and all electric and natural resource plans developed meet this forecast’s estimate for energy needs. Higher and lower load
2030-early 2040s timeframe? storage compared to other alternatives, including renewable alternatives without storage, is higher priced until that time based on our current cost assumptions. In the next 10 to 15
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 714 of 1105
competitive. We review and update these cost components every two years in the IRP cycle.
I think outside area resources particularly should be assessed. Especially Montana.
Are outside area resources being assessed? (asked multiple times)
Avista includes wind in Montana in the IRP and has found it to be a viable and cost effective resource alternative to meet
customer needs. When Avista issues request for proposals by energy suppliers in the future, this will determine if this resource is the best option. Also, the Grand Coulee Dam is not even using their full capacity, it is clean energy, and cheap. Is it being utilized?
Avista does not receive power from Grand Coulee Dam. This power is controlled by the Bonneville Power Administration (BPA) and is sold to other utilities. Avista does buy power from BPA on a day-to-day basis and may buy power from BPA on a longer-term basis in the future if it is a less costly option than from other facilities.
Forest biomass- is this on our radar? Is
this a storage resource?
Yes, forest biomass is an important resource to Avista. We are
looking to upgrade our Kettle Falls biomass facility in 2026 and we also analyze new biomass resources in the IRP.
How can Montana wind resources be utilized? Also consider Rathdrum Prairie as a wind resource
Avista has found Montana wind to be a cost-effective option to help meet resource needs. Although, actual wind acquisition from Montana will depend on a completive bidding process. The Rathdrum Prairie’s wind resource is not economically viable compared to other locations at this time.
Solar with storage- what is the storage with solar? Storage with solar is a lithium-ion battery system coupled with a solar farm. The reason for colocation is due to tax credits and the sharing of interconnection costs. Are there any limitation to transmission capacity specifically Canada or Montana? There are always transmission constraints depending on location. Avista studies potential transmission interconnection points to test if the resource can connect or what will be required to facilitate the interconnection. More renewables will
require more transmission or upgrades to existing to existing transmission resources. Heard natural gas generators area being
scrapped- please clarify if this is accurate given you have natural gas plans in your resource plan.
Avista is unsure which plants are being retired, although
Avista does have plans to retire or end contracts with some of these resources it currently uses. Given current economics, we expect some construction of new and more efficient natural gas plants in the future. Planning and deployment of storage why so late in comparison to building natural gas
Storage provides many options, but the ability to meet our peak planning requirements depends on several factors including costs and the duration of the storage device. We
mainly need energy production and storage in winter peak months and could be more reliant on storage earlier, but it will
need to be either lower cost or a modestly higher cost compared to longer duration capability resources such as new generation or pumped hydro storage.
Intermittent supply during peak demand times- Do you need back up these resources- are we doubling the energy production?
During operations we carry reserves to help handle variation from intermittent resources. These reserves are not necessarily doubling the generation required. For peak demand times we estimate a “peak credit’ for the intermittent
resource types which is a measurement of how well we can expect the resource to help us meet peak needs when they occur. Typically this is a relatively low percentage for renewables. Electric Cars- The load forecast doesn’t seem to reflect this increase Avista forecasts future EV demand and EVs are planned for and expected. Each EV could add 5 to 10 kW of load to the system. This is similar amount of power to an electric water heater. Since the amount new EV’s are unknown, Avista
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 715 of 1105
reevaluates its EV forecast each year and runs high and low EV scenarios to better understand how our plans could meet changes in that part of the load forecast. All resources have problems and nothing is
free. Nuclear is large piece of the US energy supply and the INL has DOE contract for modular nuclear. What is Avista’s thought on nuclear.
Avista continues to evaluate nuclear and it is not being chosen
in this plan due to high expected cost. Nuclear power also has additional risks from construction and waste disposal is an ongoing concern. Avista will continue to study nuclear in future IRPs and will update assumptions as more information about the modular nuclear systems is available.
Natural Gas- what is the source near Vancouver, Canada- what is the source of this Gas
Avista’s natural gas for power production comes from Alberta. The Vancouver location referred to is likely the Sumas trading hub, where natural gas is traded between British Columbia and the I-5 corridor. Natural Gas may come from British
Columbia wells, but it could go both ways.
What is a peaker? A peaker is natural gas-fired generator that typically generates during peak load events. Its typically lower cost to construct but is often more expense to operate. More efficient natural gas-fired generation is available, but it is more expensive to build and would need to run a higher percentage of the time to justify the higher costs. What about nuclear and hydrogen fusion- Is the carbon footprint of nuclear construction to great?
Nuclear is evaluated, but the cost is too high to be included at this time. Avista studied hydrogen resources in is IRP, but not hydrogen fusion. Avista also evaluates the carbon footprint of
all resources when it looks to add to the system for both construction and operations. Do we have enough geothermal resources? Avista has not identified any local options for geothermal. Southern Oregon, southern Idaho and Nevada have good options for geothermal. So far, the costs of these projects have been higher than other alternatives in our competitive bidding processes when the transmission costs to get geothermal resources to Avista are included. Pumped storage/hydro; Is this option more of rate scheme then a resource due to
pumping and generating at different times of the day? What about losses of pumping- you’re not creating energy- correct
Pumped hydro can take advantage of different pricing throughout the day or week. It could also be used for meeting
peak load events and provide reserves for intermittent generation. Yes, pumped hydro does not create energy. It loses approximately 20% of its energy when operating, but it provides a large amount of capacity and energy over a much longer period of time than other storage resources. How are outages used to meet resource adequacy? Outages would be the lowest cost alternative to meet resource adequacy but planning for outages does not make for a reliable system. There are costs involved with making a system more reliable, and we are always trying to weigh the
risk and cost trade off of making the system more reliable.
BPA had to generate its hydro at 1 GW higher then its demand- is that the case for Avista
Avista holds reserves for wind, solar, and load variations. To help with this issue, Avista is joining the energy imbalance market to pool resources with other utilities to handle this variation across a larger number of utilities and reduce the needs and costs across the wider system. Microgrids Avista Response
What is Avista’s plans for microgrids?
large scale but continue to test and monitor trends and changes in microgrid technology. This summer we will
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 716 of 1105
university. This microgrid pilot will inform decisions about their use in the future.
Security Avista Response What are your plans for hardening the electrical system against terrorists or other people capable of damaging the key very large transformer's cooling systems with
high powered rifles or explosive drones or malware?
nationally recognized security frameworks and standards to manage cyber and physical security related risks. These standards address protecting, detecting, responding and
recovering from physical and cybersecurity threats. In addition, we work with industry and government partners to ensure we are aware of emerging security risks and how best
hacking which COULD shut down energy supply (such as elec.)
nationally recognized security frameworks and standards to manage cyber and physical security related risks. These standards address protecting, detecting, responding and recovering from physical and cybersecurity threats. In addition, we work with industry and government partners to ensure we are aware of emerging security risks and how best
Natural Gas (or Renewable NG) Avista Response
scheduling? scheduling as linepack provides the ability to flow the gas for the necessary demand. As more linepack is needed, more
supply will be brought on to the system to meet the demand
project changes (on linepack/scheduling)? the supply is available to our firm customers when they need
hydrogen technology for longer terms storage? of pure hydrogen is being blended directly with the natural gas. These systems are being studied for wider application. In other systems, hydrogen is first combined with waste CO2 to make methane before being blended. In this
application, the limits are much less restrictive and much more
Hydrogen gas you want to attain in your natural gas supply and what is the soon.
affect, reduce the btu’s? somewhat less than natural gas that does not have a hydrogen blend. Regardless, the customer is charged on the
Energy Efficiency & Demand Response Questions Avista Response
to be more efficient so they don’t lose or gain heat all the time? programs. Many of these options include improving cost effective weatherization of homes. Please visit Avista’s website for information on current energy efficiency rebates and programs. In addition to prescriptive offerings, commercial
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 717 of 1105
through their account executive based on their unique energy needs and equipment.
I’ve been looking at solar as a potential option to reduce energy demands, but
learned natural gas was the main usage we have and the ROI was negative. What offsets would be helpful on the Natural Gas side to replace our demand.
Avista offers natural gas energy efficiency rebates such as Energy Star appliances, space and water heating. In addition,
there are rebates for LED lighting and smart power strips to reduce phantom loads. More information can be found on Avista’s website at https://myavista.com/energy-savings/energy-savings-advice.
From a resource planning perspective, in addition to energy efficiency on the natural gas side of the business, options include hydrogen and renewable natural gas. On the electric side of the business, reducing dependence on natural gas will require long term storage solutions to store renewable energy
incentives where the owner of a building passes heating and cooling bills to the
tenants, but the tenants don’t have long term incentives to benefit from capital investments in energy efficiency of the
continue to grapple with how to touch this hard-to-reach market. Utilities, regulators and legislators have been working
on this issue, but there is no clear consensus yet on how to handle the split incentive problem.
years. Why will it take until 2024 to launch these in Avista's territories? Response but has not pursued these programs due to their higher cost then alternative resource acquisitions. The latest
analysis shows these programs may be cost effective as an option to meet Avista’s capacity needs in 2026. We reevaluate
the costs and benefits of Demand Response programs for
homeowner's HVAC system, does that apply to given hours during a peak event? i.e., noon to 5 p.m.? Also, how would-this work? For example, if the peak event as
heat related, would this be a device placed on the HVAC that would allow Avista to alternate AC to a fan-mode in 15-minute intervals?
modeled to be used during peak heating and cooling times depending on the season for a two to four-hour time frame per participant. This can be done with either a temperature set
back or by cycling the HVAC system. The customer impact is
a two-degree offset during the requested/event period.
Heating or cooling above/below the thermostat set point, ahead of the event period, (often called pre-heating or pre-cooling) was not included in the program design we evaluated
We modeled this program in two ways, one with temperature control and one with cycle control. Either program would be
time based and would include specific parameters around
when those programs would operate and how customers could opt out for a specific event.
evaluate the energy usage of my home, such as efficiency of heating system ducts/furnace (gas), hot water (gas), and
way to understand ways you may be able to reduce energy consumption in your home. This is a free program, however, it is currently suspended due to the pandemic.
is, how does Avista deal with the natural conflict between selling energy and conserving it?
through a bill adjustment called the “EE Tariff Rider”. All customers contribute to these expenses based on the amount of energy they use that in turn will lower the cost for all
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 718 of 1105
conserving energy is mitigated as long-term profits do not relate to the amount of customer sales, but rather the investments it makes to its system that are prudent investments as determined by the state regulatory commissions. How will Avista do more to incentivize energy efficiency for middle income and low income customers? will there be rebates for homes converting to ductless
heat pump systems from natural gas? or rebates for insulating window inserts?
For low income customers, Avista fully funds energy efficiency programs such as weatherization and appliance upgrades. Community Action Agencies, such as SNAP for Spokane County, income-qualifies customers and administers the
programs. For other customers, information on current energy efficiency programs can be found on Avista’s website at
only through rebates or is on-bill financing
also an option? If so, would that be applicable to residential customers and
business customers?
implementing with a third-party lender. Avista will invoice and
collect the monthly payment and remit to the lender for qualifying energy efficiency projects. This program will initially only be available to Avista’s residential and small business
customers in Washington State and is expected to be
launched by the end of 2021. Avista is also looking at offering
reimbursement is? their Avista incentive payment for their qualifying energy
and just keeping up with regulation. Are we actually being proactive to lobby for EE improvement statewide, etc. in each
jurisdiction or are you just reacting to state
of energy efficiency programs and offerings in the northwest. These include the Northwest Power and Conservation Council and the Northwest Energy Efficiency Alliance.
effective “deemed and calculated” DR
programs, such as more efficient charging of forklift batteries or switching to efficient lighting, so why can’t Avista adopt some of those sooner than 2024?
unique system. Costs and customer needs are often different
for each utility. Demand Response programs are different than Energy Efficiency Programs. Demand Response stops energy use for a period of time or shifts it, versus energy efficiency programs using less energy to get the same amount of work or process completed. Avista’s first DR programs will be rate
related programs to incent use in non-peak hours. Over time as more controllable load is added to the system, it is likely
feed-in tariffs? Is Avista advocating for those? the utility. Currently the only program similar to this option is generation provided under PURPA (Public Utility Regulatory Policies Act). No other state regulation requires a feed in tariff
neighborhood-scale geothermal, e.g. small thermal differential circulation pumps for heating or cooling costs. Avista welcomes developers to pursue this option and it may qualify for energy rebates.
neighborhood-scale renewable energy, such as solar gardens, Swedish-style local governments that allows property owners to finance
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 719 of 1105
neighborhood heating and cooling, and property-assessed clean energy financing (PACE).
through a property tax mechanism. Washington and Oregon have passed legislation allowing these programs, however, no
counties in Avista’s service area have an active PACE program. Avista is currently developing an On-Bill Repayment (OBR) program that will be available to owner occupied
buildings for both residential and small business customers in
Washington State by the end of 2021. Avista is also looking at possibilities to offer OBR for our Oregon and Idaho customers in the future.
Has Avista ever thought about putting timers on hot water heaters? I have one on mine and it’s amazing how it keeps my energy down.
Avista has evaluated controlling water heaters and at this time found it to be non-economic compared to other options. Although Avista continues to evaluate this option and other options, so it may become cost effective in future plans. What about AMI? Any EE benefits? Yes, AMI energy efficiency benefits include customers reducing their usage from having access to near real time
information and conservation voltage reduction on Avista’s
distribution system. The customer program for AMI energy
efficiency has partially been implemented with the availability of near real time usage on-line. Usage alerts and notifications,
as well as data analytics for “always on” usage is under
development and will be made available soon. Conservation voltage reduction is currently in use in Avista’s day-to-day operations.
Additional AMI benefits, including energy efficiency, can be found on Avista’s website at https://www.myavista.com/about-
us/smart-meters.
solar project as they once had in the past? that will provide more renewable options to our customers. At
but Avista intends to continue the energy fairs in the future
Reliability Avista Response
winter event when it is cold and dark with
no wind or solar production?
hydro resources to maintain system reliability for extreme
winter events until long-duration storage resources become
power grid from reliable power sources like hydro, gas, coal and nuc, to unreliable portfolio but will ensure reliable service by continuing to invest in capacity capable resources such as hydro and energy
will be based on these unreliables in the next 10, 15, 20 years? sales will be served by clean energy resources., A portion of this generation will be from wind and solar, as well as hydro
avoid the types of problems Texas just encountered? Are different plans needed to prepare for damage from wildfires?
supply are designed to withstand cold temperatures. Because of our climate, this has already been done. The second protection is to ensure Avista plans to add or maintain enough generation to serve customers during high load hours like
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 720 of 1105

Comments provided in breakout sessions, email, or chat feature
Inverted energy rates.
to determine the mix of resources needed to serve loads in these types of events. Avista is currently working with outside agencies and regulators to develop a wildfire plan but is well positioned to repair and replace damage to infrastructure from
energy potential here to increase substantially? If so, how do you estimate the storage needed, for times when wind
or solar or hydro. is supplying less than usual?
including wind and solar, as other regional utilities are also planning to do. The plan calls for at least 400 MW of additional wind and nearly 500 MW of solar over the next 24 years. The
amount of storage will depend on the actual acquisition of specific resources and whether Washington will require real-time delivery of clean energy to its customer. For now, Avista’s resource plan only plans to add 266 MW of storage, but if costs decline additional amounts could be added. The resource plan uses several modeling tools to determine how
much energy can be relied upon for wind, solar and hydro
and solar are not available resources to meet this demand from intermittent resources. In the future energy may be stored in batteries, pumped hydro or
that resources are limited? particular price or cost or during periods of extreme weather
OR, and ID as what Texas is experiencing--why not? How will AVISTA and these states avoid the same fate? How do you
expect to do the same program and expect different results?
Avista plans to meet extreme cold and hot events, second Avista plans for resource adequacy. Texas does not have a regulatory requirement to ensure capacity during cold or hot
weather events. Another major issue in Texas was fuel suppliers, specifically for natural gas, were not prepared and their equipment was not designed for cold weather events. In Avista’s case, its natural gas supply comes from Canada
energy, the problem with disposing of them
when they are obsolete, and seeing the fiasco in Texas, should wind even be a
resources, the technology can still be economic to replace
energy needs in other time periods.
warm and safe in the winters beyond 2025? 2026, the Company intends to address this in many ways including the issuance of a capacity RFP, possibly as early as 2021. In addition, the current IRP does not include any resource acquisition that may result from the 2020 Renewable
General Avista Response
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 721 of 1105
Hopefully people only home in the evening won't get penalized for using power at that time, but rather people fortunate enough to be home during times of lower use & lower costs could get the bonus of a lower rate. Use-and-rate schedules are unnecessary. They are a recipe for prejudice. We have the resources to
meet the needs of all people. Avista is playing games with the seriousness of human life. Policy
I wish that AVISTA would honestly not move forward with the April plan. I am sure you can resist and not comply with a bureaucratic environmental agency or with elected representatives who are in office based on computerized counting procedures that do not mirror the interest of the public which was shown by candidate signs in yards this fall. Reliability
I never want to hear from you that we're experiencing power outages because of reliance on green energy sources.
We need to use all sources of energy.
Finally, I'm certain the survey question regarding reliability is knee jerk to the situation Texas, even more than the outages due to the recent wind event. Our grid isn't isolated, like in Texas.
I've taken a little time to review Avista's draft 2021 Integrated Resource Plan. Although Avista doesn't come out and say this will happen, it seems we should expect mid-winter rolling blackouts after 2025 when Avista's predicted demand will exceed electrical supply. Think of California with its utility-induced blackouts last summer, and the human tragedy and equipment destruction this winter caused by inadequate power planning in Texas. We don't want to fall into that kind of third-world situation here. I know we have a PUC and an Office of Energy and Mineral Resources but neither seems to be
focused on this looming issue. I have attached some poignant excerpts from the IRP for your consideration. The full IRP can be found here: https://www.myavista.com/about-us/integrated-resource-planning
It's not very comforting to learn that Avista is "concerned" about not having adequate power generation after 2025, and that they are "hopeful" that something will be done on the regional level, but sadly they have no concrete solution. This does not sound like a very good contingency plan to me. If the Region needs new generating capacity and novel utility coordination to meet peak winter demand, and considering how long it takes to plan,
finance and build large projects, it sure seems the energy outlook is not looking good for our area. It's rather troubling that Avista has put its customers in this predicament after their failed attempt to merge with Canada-owned Hydro-One in 2018. I think Avista is putting our state at risk by relying so heavily on unrealized Regional solutions that are out of Avista's control. Avista hopes somehow the Regional players will create sufficient new generation and squeeze higher efficiencies out of a stressed and vulnerable network within the next 5 years. That seems far fetched; but if not, Avista should let us
know the positive news before we all go out and buy whole house generators. It seems part of the diminishing supply problem stems from green initiatives of neighboring states and Federal mandates forcing the elimination of reliable "thermal" generation in favor of unreliable, and thinly available "renewable" energy sources.
I see you are Chair of the Resources and Environment Committee, so hopefully you will have some ideas on how to pursue this issue. Idaho might already be behind the 8-ball because 2025 is looming mighty fast and there is hardly any clear answer to the coming power shortage, other than the obviously un-said "rolling black outs". According to Cliff Harris, our local weather guy, we are due for a
really big winter, bigger than 2007-2008, due to the solar minimum, etc. So all I can suggest is maybe get the appropriate committees to ask Avista and the Governors Energy office the tough questions: how will they keep north Idaho people warm and safe in the winters beyond 2025?
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 722 of 1105
I am no expert, just an ordinary retired person with questions about the future. Thank you for considering this concern.
Affordability & Equity I'm not interested in wind/solar construction. It has its place, but it is not 24/7, w/out expensive and environmentally destructive storage. isn't all this a windy way of saying you’re going to charge us more and just in time for the new minimum
wage that has driven the cost of goods and services up to match. but wait grasshopper, no one raised the checks of the retired and disabled. only the prices went up which lowered the living standard of the most defenseless among us. so now you want to join slaughter. ROFL "Affordability" Environmental
Move to a ZERO carbon dioxide emissions format ASAP. I'm not interested in wind/solar construction. It has its place, but it is not 24/7, w/out expensive and environmentally destructive storage
Use renewable energy to affect the mixture of natural gas and hydrogen in pipeline systems. I am very concerned about Governor Inslee's plan for green energy. Wood biomass is pollutive.
I don't think that cost is a factor that should limit the use of Small Modular Reactors. Wind machines are expensive too. They harm birds. They harm people. They require bare land. They are unsightly. They are not biodegradable. They are a fool's errand.
Commitment to environment is a vague statement that doesn't give any information as to what you will do or not do. What about the waste from windmill blades and old solar panels?
The United States of America has been quite clean thus far; we do not need to become more so. We need to maintain our life. This is getting to be a matter of survival. All electricity is electricity; it would
be a fool's game to tell customers they are getting their electricity from wind or sun and not from hydroelectric dams. That is all bogus marketing. Telling customers they can pay for "green" energy is a credit that is all on the books and this is not tied to reality. Any way that financiers can play with
money and that customers can be billed more or less for fees or peak loads or anything else is all "make-work" schemes for billing departments, computer programs, marketing webinars like these
public forum meetings, which are a ploy to lead us to think we can stop what you are already planning to implement because you are "committed." Your company has co-opted the best, most noble vocabulary and is using it to name your plans which will actually destroy the lives of people and the economy of America. A sample of your vocabulary includes "power production," "load growth," "lens," "focus," "committed."
The shut down of the Colstrip plant in Montana is a real sore point with many in our circles. "Storable" consistent coal still accounts for over 60% of all the power generated in the U.S., and to pretend that
intermittent wind and solar can in the near term (let alone ever??) replace coal without natural gas, nuclear and hydro expansions, is irritating to many of us. The tribal influence of less than 10,000
members in our region, over the welfare of millions of U.S. citizens, is of great concern to us. I had put in some questions about Colstrip that I hope get publicly answered. Is the power generated by U.S. plants like Colstrip really that "dirty"? (U.S. companies are leaders in scrubbing pollutants out of
exhausts.) Is the public being sold a false narrative in that regard, due to political pressures? Could that plant be leased by Avista and run by the utility if the tribes don't want to do it? Could a new state of the art back up plant for wind farms and solar, be built at a reasonable cost? Resource Selection
Liquid Metal Batteries, Pumped Hydro, Solar incentives, net metering buy backs over used power CANCEL ALL PLANS FOR ADDITIONAL WIND TURBINES, I am totally against the removal of the J C Boyle Dam, Copco Dams 1 & 2, and Irongate Dam, I also support solar power, but within limits. I support properly designed nuclear power. And I support Avista's natural gas projects. Avista clearly does not want to discuss “nuclear options”. I keep hoping that the miserable and
complex failure of WHOOPS won’t sour this region forever on that possibility.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 723 of 1105
Since you have already seen the evidence of catastrophic failure in Texas, how does that not put you in legal jeopardy for future failures in WA, ID, and OR? Wind is a joke. There can be no wind. The turbines can freeze. The blades are made of fiberglass. They are so big, they must be brought in one per truck. Fossil fuels are needed to transport them. They are not biodegradable. Just like China, we need to forestall any changes from our present energy forms until we have more technologically advanced forms of energy. Wind and sun are NOT advanced forms. Our present federal-level
administration is not legitimately elected. We are fools to limit ourselves to obeying their suicidal goals. We need to think other than wind and solar. It is primitive. Your questions are lose-lose. The multiple
choices offered are not innovative and are not evidencing out-of-the box thinking.
General Avista should look into internet and television and other services by using the resources that are already in place for remote area within the Avista service area Choosing among affordability, environmental responsibility and reliability is a false choice. These need to be balanced, as you say. Why is the assumption so strongly held that resources are limited? If we (mankind) are able to use the powers of the mind to make new discoveries of the physical world around us, why don't we get out of this doomsday outlook which says we are limited to the energy platform we are already on? We ought to be spending our time and strength building on the steps we have already taken to be able to land on
the Moon and voyage to Mars, in order to get new forms of energy available to us. Specifically, environmentalists have blocked nuclear power energy. However, NuScale's Small Modular Reactors
are as clean as wind, solar, and are cleaner than any fossil fuel. I think AVISTA ought to push back against Washington State's population-reducing polices. Our country was founded to promote the General Welfare of all the people, but Washington State, Oregon, and California's governors and Democratic Party controlled legislatures are horrifically proving they care nothing for the general public. 60% of my electric bill is how much money I already spend on gas. Ride sharing and mass transit is the answer. I'm concerned about safety and shocked at the answers of indifference in where plants are located. I voted for away from communities.
When does Avista plan to stop extorting their customers then later boasting about record profits? Avista overcharged customers by a total of $43 million, according to a ruling by the Washington State Court of Appeals.
The Washington Utilities and Transportation Commission has directed Spokane-based Avista Corporation to refund $8.4 million to electric and natural gas customers in Washington state.
The conversation is legitimizing foolish options. We are not limited the way you think we are. Please
focus on scientific discovery of new ideas, like Benjamin Franklin and Thomas Edison did. We will not be able to maintain what we have because the production of these "green" "clean" energies are production-dependent on our present system. More noble vocabulary being misused to promote the possibility of a Texas-type disaster: resources, reliability, clean, attentive to, responsible to the environment, generation, strategy, scalable, ensure, pre-credit, production history, resources, renewable, reduce carbon foot-print, need energy, build our needs, deliver, service territories, demand response, retiring existing resources, social cost of carbon,
voluntary offering, energy efficiency, advancing technologies, lowering costs, hydrogen blending, opportunity matures, forecasted. All of this vocabulary puts a great-sounding face on plans for your
reduction of perfectly good forms of energy in present use and divvying it out piece-meal to the result that the people will be diminished and in grave danger of dying off from supposedly new ideas, which are actually nothing at all beyond just sitting outside in the cold. I think "carbon-footprint" is a false boogey man that AVISTA is foolishly bowing down to and carrying the rest of the people to do the same. I think your assumptions and definitions need to be re-visited and reviewed. You are limiting yourselves, I believe. Ecologists and environmentalists have a foolish and damaging overall philosophy and set of
assumptions. Basically, they believe what Malthus said, namely, that the earth is not able to support a growing population. Actually, God said to be fruitful and multiply. He has made man with the ability (of his mind and powers of observation) to DISCOVER new ways to harness the natural laws and physical qualities of the earth. Please re-think your philosophy.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 724 of 1105
I found the meeting very informative. Another example of how Avista is a stellar partner in our community. I was interrupted in my second breakout meeting but I still have a question; “What does your company anticipate the impact to be from the forthcoming increase in electric vehicles and how will you prepare for that?” This is probably an industry wide question with a complex answer. You don’t need to answer me directly but point me to articles on the subject. Why is wind/solar is renewable when you can’t renew them; but natural gas it’s not always there where natural gas is renewable as it comes from the earth

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 725 of 1105

Sent Via email to: [e-mail]
July 31, 2020
Mr. Lyons and the Avista IRP Team,
Thank you for the opportunity to request additional studies as part of the 2021 IRP process. Our requests below include some process improvements to the existing studies in the IRP as well as some new considerations. In each instance, our goal is to ensure the IRP leads to the least cost and least risk portfolio of supply side and demand side resources. As the complexity of the electric system increases, as the economics of resources change rapidly, and as new issues become even more acute, we encourage the Avista IRP team to lean into this process and set an example for the region for a best in class IRP process. We look forward to working with you and the rest of the Technical Advisory Committee to achieve these goals. Contact us anytime using the information
below
Stay safe, stay healthy,
Ben Otto Idaho Conservation League 208-345-6933 ext 12
[e-mail] Dainee Gibson Idaho Conservation League [e-mail]

Study and Process Improvement Requests
Systemwide v state specific resource additions
At the first Technical Advisory Committee meeting, Avista indicated the PRiSM model could add resources to Washington and Idaho separately or to the combined, interconnected system. We request a study of the costs and timeline necessary to replace the fossil-fueled component of the 35% of existing resources allocated to Idaho with an optimized portfolio of non-fossil resources including supply-side, demand-side,
and storage resources. We request Avista compare the results of this Idaho-specific study to the results of the same analysis at the system-wide level. We also request a study that documents the costs to implement, monitor and document the state-specific addition of resources to an interconnected system dispatched to meet combined customer loads.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 726 of 1105
Existing resource costs
We request Avista study a scenario that applies the Social Cost of Carbon to all resources, including those that serve Idaho, as offered in the first TAC meeting.
We request Avista study scenarios for Colstrip costs that reflect the changing ownership shares currently being considered by co-owners Puget Sound Energy, Northwestern Energy, and Talen. Further, we request a study of likelihood and scale of increases to Avista’s share of common plant costs, remediation costs, and fuel supply costs, including minimum fuel supply and generation off-take, attributable to both the closure of Units 1 and 2 and the changing ownership share of Units 3 and 4.
We request a study of the accuracy of Avista wholesale natural gas price forecasting methodology by comparing forecasted prices in prior IRPs to prices Avista actually paid. We request this study include a comparison of the accuracy of consultant-supplied
forecast to publicly-available forecasts covering the same time periods.
Storage
Storage resources provide unique attributes that are not captured in traditional IRP modeling techniques that focus on energy and capacity needs in the hourly time scale. Storage technologies like Li-Ion batteries with fast reaction times, but only a few hours of capacity can address power quality and reliability needs within the hour. Medium term storage resources, such as Li-Ion batteries with 6 - 12 hour capacity,
and pumped storage projects, can help integrate variable energy resources and address reliability needs. Longer term storage resources like hydrogen electrolysis paired with storage and repowered turbines, can address integration, reliability, and resiliency needs. By combining these storage resources with specific clean generation options, Avista can develop clean resources that meet the reliability metrics for flexibility, peaking, and renewable integration necessary to meet Avista’s clean energy goals as well as CETA requirements.
To ensure a full and fair treatment of storage values we request the following:
• We request Avista model loads and generation at the sub-hourly level. We recognize Avista began pursuing sub-hourly modeling in the 2017 IRP and further refined the ADSS system in the 2019 IRP. We request Avista fully implement sub-hourly modeling for all IRP studies and processes.
• We request Avista study the optimal pairing of generation resources with storage of different technologies and lengths of supplying services. For example: pairing local solar or wind with Li-Ion 4hr, 6hr, and 12hr batteries; pairing pump hydro
resources with regional solar, wind, and wholesale markets; pairing long term storage like hydrogen electrolysis and associated hydrogen storage with Avista’s own resources and wholesale market generation.
• We request Avista study the emission reductions possible from pairing storage with specific clean generation options along with the Proposal presented to the TAC to apply the average emissions rate of the region for storage paired to generic wholesale market resources.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 727 of 1105
Distribution level modeling
Distributed energy resources are increasing as products diversify and the economic proposition improves. To help encourage the optimal growth of DERs on the Avista system, we request a Hosting Capacity Analysis. This analysis could support a distributed energy resource interconnection map that identifies where distributed energy resources exist on the system or where the distribution system is constrained and could benefit from energy storage or specific demand responses. This Hosting Capacity
Analysis would benefit the IRP’s load forecasting and overall integration of distributed energy within the IRP. We recommend Avista define DERs broadly for this study to include: customer-sited generation and storage, utility-sited generation and storage at substations or other locations on the distribution grid, as well as public and private electric vehicle charging stations. We request Avista incorporate different load shapes that are indicative of customer generated power as well as the charging of electric vehicles to ensure accuracy in the load shapes for supply-side resource planning. The Smart Electric Power Alliance has an informative set of resources to help with this effort: https://sepapower.org/knowledge/proposing-a-new-distribution-system-planning-model/.
Flexibility Issues
With the technological changes of a modern grid system, including flexibility in both supply and demand studies is essential as we look to the future of electric service areas.
As shown in the pilot program with the Catalyst Building, the savings from energy efficiency and flexible building loads can be extremely beneficial for the electric grid as a whole. Similarly, the micro-transaction grid project in the Spokane University District is demonstrating the value of flexible loads and new market opportunities for customers to manage their power bills. To fully explore the value that flexibility brings to Idaho customers, we request Avista study the potential to expand similar projects in the Idaho service territory. At minimum, a study to see the perspective of customers’ willingness to participate in such a pilot program could have lasting results.
Climate Change Impacts to Avista’s System and Costs
In the 2020 IRP, Avista describes how climate change is causing a rise in temperatures today in the service territory and, therefore, is influencing the load forecast. To further examine how the currently changing climate can impact the system and costs, we
request Avista build upon this by studying the following:
• Loads - study changes to both long-term load forecast and the peak load forecast attributable to climate change. The 2020 IRP mentions a 1-degree increase in temperatures, but does not appear to describe how climate change is factored into the peak load forecast. The 2020 IRP also cites a temperature data set from 2013, which we recommend Avista update to the most currently available set.
• Hydro - study the potential changes to hydroelectric power generation that could result from climate-caused changes to precipitation type and timing. This study should document the range of impacts to power costs that result from the changes in hydroelectric power generation.
• Thermal plants - study potential changes to expected generation and production costs due to temperature changes. This study should include changes to expected generation and fuel costs as output varies with ambient temperatures
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 728 of 1105
and the impacts to cooling water needs due to changes in precipitation and water temperatures. The study should document the range of impacts to power costs due to the change in expected generation output, fuel needs, and cooling water needs.
Beneficial electrification
One of the most interesting long-term planning issues to address in the 2021 IRP is how increasing electrification of transportation can benefit the system and customers. Idaho currently imports 100% of our transportation fuels. Electrifying transportation can make
Idahoans more energy secure and reduce costs since we pay above average fuel prices and below average electricity prices. And optimizing charging practices can deliver further benefits to all electric customers. The 2020 Transportation Electrification Plan (TEP) states that “In 2025, over 6,800 EVs are expected to provide Avista with gross revenue of $2.1 million from EV charging. Subtracting an estimated $0.5 million in marginal utility costs to generate and deliver this energy results in $1.6 million in net revenue – savings which may be passed along to all utility customers in the form of decreased rate pressure.” To ensure Avista is prepared to serve Idaho’s clean transportation needs, we request:
• The load forecast includes the baseline projection of electric charging services,
as forecasted in the 2020 TEP. We also request scenarios that consider higher penetration of EV, especially for commercial fleets, delivery vehicles, and public transportation.
• A study of how to optimize charging behaviors, including customer load management, and how to optimize the location of public and workplace charging stations to avoid distribution grid overload while maximizing grid flexibility and benefits to the system. For example, the TEP identified that the $1,206 in electric system benefits per EV could “be increased by another $463 per EV when load management shifts peak loads to off-peak.”
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 729 of 1105
Hello Ben and Dainee,
Thank you for your continued participation and involvement in Avista’s IRP. Here are
the replies to your 2021 IRP study requests and suggestions for process improvements
to ongoing studies.

System wide versus state specific resource additions
• “We request a study of the costs and timeline necessary to replace the fossil-
fueled component of the 35% of existing resources allocated to Idaho with an
optimized portfolio of non-fossil resources including supply-side, demand-side,
and storage resources.
Avista is developing a portfolio with all renewable/GHG emissions free
resources as it did in its 2020 IRP.

• We request Avista compare the results of this Idaho-specific study to the results of the same analysis at the system-wide level. Yes, we will highlight the comparisons of the system-wide versus the Idaho-specific study in the IRP.
• We also request a study that documents the costs to implement, monitor and
document the state-specific addition of resources to an interconnected system
dispatched to meet combined customer loads.
The cost allocation for new assets constructed to meet the Washington
CETA law has not been decided by either Commission yet. An IRP does
not answer this question. The 2021 IRP will attempt to evaluate the cost
deltas between portfolios absent CETA mandated acquisition targets.
Avista looks forward to working with both commissions and interested
parties on this issue as new analyses become available.

Existing resource costs
• “We request Avista study a scenario that applies the Social Cost of Carbon to all
resources, including those that serve Idaho, as offered in the first TAC meeting.”
Avista will conduct this study in the 2021 IRP.

• “We request Avista study scenarios for Colstrip costs that reflect the changing
ownership shares currently being considered by co-owners Puget Sound Energy,
Northwestern Energy, and Talen. Further, we request a study of likelihood and
scale of increases to Avista’s share of common plant costs, remediation costs,
and fuel supply costs, including minimum fuel supply and generation off-take,
attributable to both the closure of Units 1 and 2 and the changing ownership
share of Units 3 and 4.”
Regarding the change in ownership percentages for Units 3 and 4, there
are no changes to Avista’s responsibilities or modeling inputs to alter
because Avista’s 15 percent share of both units remains static under the
Colstrip ownership agreement. Avista’s financial responsibility for the plant
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 730 of 1105
remains the same regardless of the non-Avista ownership or ownership percentages for Units 3 and 4. As in the last IRP, Avista is accounting for
the shift (increase) in previously shared costs that are a result of the
closure of units 1 and 2. Those costs increased, but Avista’s share of
those costs did not change. Avista has zero responsibility for the
remediation costs associated with Units 1 and 2. The closure of those
units did not end the financial responsibility of those remediation costs for
the owners of those units (Puget Sound Energy and Talen). Avista’s fuel
contract is separate from the contracts that supplied Units 1 and 2.
Avista’s fuel contract and any subsequent mine remediation costs with our
share of coal are already included in the prices being modeled in the 2021
IRP, consistent with past IRPs.

• “We request a study of the accuracy of Avista wholesale natural gas price
forecasting methodology by comparing forecasted prices in prior IRPs to prices
Avista actually paid. We request this study include a comparison of the accuracy
of consultant-supplied forecast to publicly-available forecasts covering the same
time periods.
The natural gas price forecast beyond the shorter term forward markets is
always an area of concern because of the potential for volatility, timing
and magnitude of outside events, much like the current pandemic we are
now experiencing. It is in our own best interests to use good forecasts.
Avista publishes its natural gas price forecasts in each IRP; including both
consultant forecasts on an annual average basis. Actual natural gas prices are also publicly available. The consultants that we use work on a national
as well as an international basis. They already perform their own internal analyses to make their forecasts as accurate as possible to maintain and
grow their business. We are paying for their expertise and research into the natural gas market. Avista has not seen any evidence indicating that there are better forecasts available and we do not possess the resources to develop a comprehensive fundamentals based natural gas forecast on our own. Some forecasts, like those provided by the Energy Information Administration, supply some more details about the fundamentals they are using, but they are also more dated and do not provide the level of granularity into specific trading hubs. The consultants would not be able to remain in business if they had to give away all of their research for free. Please let us know if you have found other evidence or research indicating
better forecasts. Storage
• “We request Avista model loads and generation at the sub-hourly level. We
recognize Avista began pursuing sub-hourly modeling in the 2017 IRP and
further refined the ADSS system in the 2019 IRP. We request Avista fully
implement sub-hourly modeling for all IRP studies and processes.”
Sub-hourly modeling is challenging due to model solution complexity and
data availability. Further, modeling all sub-hourly periods is not
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 731 of 1105
technologically possible. Presently, modeling at one-hour granularity requires thousands of hours of computer processing time. Moving to intra-
hour modeling would cause an exponential increase in solution time even
if the data was available. ADSS and other modeling techniques are used
to evaluate intra-hour values, and generally rely on sampling of relevant
time periods. This is specifically the case with the complexity of modeling
storage resources. Avista is working on this issue and is hopeful it will be
available in future IRPs and will be added as an Action Item in the 2021
IRP if not completed for this plan.

• “We request Avista study the optimal pairing of generation resources with
storage of different technologies and lengths of supplying services. For example:
pairing local solar or wind with Li-Ion 4hr, 6hr, and 12hr batteries; pairing pump
hydro resources with regional solar, wind, and wholesale markets; pairing long
term storage like hydrogen electrolysis and associated hydrogen storage with
Avista’s own resources and wholesale market generation.”
As described in the first TAC meeting and distributed to the TAC
afterwards, this IRP is already including a wide variety of stand-alone
storage and combined renewables plus storage options. The options
being modeled include distribution scale 6-hour Lithium-ion; 4, 8 and 16-
hour Lithium-ion; 4-hour Vanadium flow, 4-hour Zinc Bromide flow
batteries; 16-hour 100 MW share pumped storage; and 100 MW solar
photovoltaic with 200-MWh Lithium-Ion batteries. Avista is also modeling
hydrogen using fuel cells or converted combustion turbines. Each of the hydrogen options will include long duration storage facilities as a backup
to real-time deliveries. Avista’s IRP modeling includes the benefits from a portfolio optimization in its current process between storage and
renewable resources. Avista acknowledges there could be a benefit to pairing storage with renewables from a transmission perspective. Although the locational benefits of storage paired with resources may not be optimal when considering other “better” locations to locate the storage. Avista agrees with this concept and is trying to determine the best methodology to model these potential benefits, but the modeling of this concept may not be available in time for this IRP. It will be added as an Action Item if we are not able to develop the concept and include it in the 2021 IRP.

• “We request Avista study the emission reductions possible from pairing storage
with specific clean generation options along with the Proposal presented to the
TAC to apply the average emissions rate of the region for storage paired to
generic wholesale market resources.”
Avista includes regional emissions for storage not connected to a facility;
for paired resources, Avista does not include the emissions when using
the paired resources. Although, over time as paired solar/storage
resources are no longer obligated to use the paired resources storage
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 732 of 1105
technology to satisfy tax credit requirements will likely use a combined grid/local power for optimization of the system.

Distribution level modeling
• “To help encourage the optimal growth of DERs on the Avista system, we request a Hosting Capacity Analysis. This analysis could support a distributed energy resource interconnection map that identifies where distributed energy resources exist on the system or where the distribution system is constrained and could benefit from energy storage or specific demand responses. This Hosting Capacity Analysis would benefit the IRP’s load forecasting and overall integration of distributed energy within the IRP. We recommend Avista define DERs broadly for this study to include: customer-sited generation and storage, utility-sited generation and storage at substations or other locations on the distribution grid, as well as public and private electric vehicle charging stations.” Avista’s transmission and distribution departments are working on a public process for this type of planning. This process will likely be separate from the IRP process, but will provide information for the IRP. More details of
this process and its findings will be shared with the TAC as they are developed.

• “We request Avista incorporate different load shapes that are indicative of
customer generated power as well as the charging of electric vehicles to ensure
accuracy in the load shapes for supply-side resource planning. The Smart
Electric Power Alliance has an informative set of resources to help with this
effort: https://sepapower.org/knowledge/proposing-a-new-distribution-system-
planning-model/.”
Avista welcomes the information, but at this time is using data collected
from its local system for both solar and electric vehicles.
Flexibility Issues
• “With the technological changes of a modern grid system, including flexibility in both supply and demand studies is essential as we look to the future of electric service areas. As shown in the pilot program with the Catalyst Building, the savings from energy efficiency and flexible building loads can be extremely beneficial for the electric grid as a whole. Similarly, the micro-transaction grid project in the Spokane University District is demonstrating the value of flexible loads and new market opportunities for customers to manage their power bills. To fully explore the value that flexibility brings to Idaho customers, we request Avista study the potential to expand similar projects in the Idaho service territory.
At minimum, a study to see the perspective of customers’ willingness to participate in such a pilot program could have lasting results.”
Avista appreciates the comment to also consider Idaho as a test bed for future projects and will take this under advisement. Avista utilizes the
University of Idaho for several R&D efforts through a grant process for a
total of $270,000 to study efforts related to energy efficiency and flexible
building loads. Example projects from the 2019/20 academic year include:
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 733 of 1105
a program design for energy trading system for consumers, using infrared cameras for building controls, and gamification of energy use.

Climate Change Impacts to Avista’s System and Costs
• “Loads - study changes to both long-term load forecast and the peak load
forecast attributable to climate change. The 2020 IRP mentions a 1-degree
increase in temperatures, but does not appear to describe how climate change is
factored into the peak load forecast. The 2020 IRP also cites a temperature data
set from 2013, which we recommend Avista update to the most currently
available set.”
Climate change is being included in the load forecast as a scenario, which
was covered in the special TAC meeting on August 8, 2020 after we
received this letter. Further, all load forecast scenario data is available on
the IRP website. Please let us know if you have any additional questions
or concerns that may have arisen since that presentation.

• “Hydro - study the potential changes to hydroelectric power generation that could result from climate-caused changes to precipitation type and timing. This study should document the range of impacts to power costs that result from the changes in hydroelectric power generation.” We have obtained the climate adjustments developed by the Power Council and are reviewing them to determine how they might be incorporated into the 2021 IRP. More details will be presented at a future TAC meeting.
• “Thermal plants - study potential changes to expected generation and production costs due to temperature changes. This study should include changes to expected generation and fuel costs as output varies with ambient temperatures
and the impacts to cooling water needs due to changes in precipitation and water temperatures. The study should document the range of impacts to power costs
due to the change in expected generation output, fuel needs, and cooling water needs.”
Avista agrees temperature changes will impact the amount of production
from its natural gas-fired facilities. This impact will be included in the
climate change scenario.

Beneficial electrification
• “The load forecast includes the baseline projection of electric charging services,
as forecasted in the 2020 TEP. We also request scenarios that consider higher
penetration of EV, especially for commercial fleets, delivery vehicles, and public
transportation.”
Avista studied increasing EV penetration in the 2020 IRP. At this time,
Avista will need to focus on other scenarios for this IRP because of the
limited amount of time available for modeling.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 734 of 1105
• “A study of how to optimize charging behaviors, including customer load
management, and how to optimize the location of public and workplace charging
stations to avoid distribution grid overload while maximizing grid flexibility and
benefits to the system. For example, the TEP identified that the $1,206 in electric
system benefits per EV could “be increased by another $463 per EV when load
management shifts peak loads to off-peak.”
Avista is updating its EV demand response program assumptions and this
will be discussed at the September TAC meeting. Avista welcomes this
discussion at the upcoming meeting to ensure it has robust assumptions
for this IRP.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 735 of 1105
August 18, 2020
RE: Electrification Assumptions in August 6 Avista IRP Presentation
Dear Mr. Gall, Mr. Pardee, Mr Lyons, and the Avista IRP team,
We appreciate the opportunity to provide comments on Avista’s IRP. This comment letter focuses on
considerations regarding the electrification of end uses scenario that the company is considering.
Washington state adopted greenhouse gas limits during the 2020 legislative session that direct the state to
reduce total emissions by 95% compared to 1990 levels, or approximately 5 million tons of CO2e by 2050; for
comparison, residential and commercial use of natural gas was responsible for approximately 7.3 million tons of
CO2e emissions in 2015. In order for the state to achieve its overall limit, it is clear that this total must decline
precipitously and studies indicate that electrification is likely the least cost pathway for doing so. Washington
State’s Deep Decarbonization Pathway Study, which was aimed at a less ambitious reduction target of 80%
compared to 1990 levels, called for 85% reductions in residential gas use and 43% in commercial gas use
reductions.
Evaluating electric sector impacts of this scale of reductions is important, and doing so must be informed by
current and reasonable assumptions about appliance performance. Below we provide recommendations to
update Avista’s assumptions regarding representative heat pumps and water heaters, as well as additional
considerations to properly model their impact on the company’s system. In particular, we think it is reasonable
to assume that over the period considered in the IRP, electric space and water heating choices will become
dominated by heat pumps, especially with the salutary involvement of the company.
Washington’s residential energy code already preferences heat pumps given their high efficiency, a preference
that will only be strengthened as the code goes through subsequent updates along the path to 70% less energy
consumption by new buildings by 20311 and as carbon is accounted for in code as it now is under WSEC 2018.
Likewise, for customers that are converting from gas or another fuel source, they are likely to opt for the most
cost-effective long-term option. This is already heat pumps rather than electric resistance units, and the
economics of this choice will continue to improve.
Electric Heat Pumps
Avista suggests that end use efficiency of electric space heating at 35 degrees would be 150% (COP=1.5) and
100% at 5 degrees (COP=1). This does not accurately reflect the current state of the market. Climate Solutions
reviewed the Northeast Energy Efficiency Partnership’s (NEEP) Cold Climate Air Source Heat Pump List. NEEP’s
definition of “cold climate” is any IECC climate zone of 4 or higher. Avista’s service territory meets this definition,
containing zones 5 and 6. NEEP’s list contains nearly 8,000 air source heat pumps available on the market today
from 89 manufacturers.
The average COP for the listed heaters operating at their maximum capacity at 5 degrees Fahrenheit is 2.09, and
the lowest COP for the models they catalogue is 1.75 at that temperature. A number of models do indicate they
would switch to backup heat at lower temperatures, but 4 out of 5 do not include a condition for switching and
1 RCW 19.27A.160
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 736 of 1105
would continue operating at the rated COP. Below is a histogram showing the distribution of various COPs
within this product list.
Below we also provide the
the average COP at a variety
of other temperatures
included in NEEP’s list.
Because customers living in
cold weather are most likely
to acquire a heat pump
calibrated to their needs, and
because this technology
invariably will continue to
improve, we recommend that
Avista change its end use
efficiency assumption for
space heating to at least
200% efficiency at 5 degrees,
and adjust the end use efficiency statistic at 35 degrees consistent with the data provided in NEEP’s database.
Ambient Temperature
(degrees Fahrenheit) Average COP at Rated Capacity Average COP at Max Capacity
17 2.75 2.45
47 3.81 3.58

Water Heaters
While there are heat pump water heaters (HPWH) available that perform at the low level Avista selected for 5
degrees, we do not think selecting the bottom of the market is a prudent choice. In 2018, Energy 350 completed
field tests in a variety of conditions of HPWHs in British Columbia, including at locations that lie just outside of
Avista’s service territory. A summary of their results are available here.
Energy 350 chose two HPWHs, one from Sanden and another from Rheem and evaluated their operation over
the course of a year. The Sanden model was a split system, with a unit located outside, while the Rheem model
was designed to directly replace a traditional water heater located in conditioned and semi-conditioned spaces.
Their COP results bear out these differing designs. On the next page are scatter plots showing the observed
performance of these systems at various temperatures, along with their lines of best fit.
From these results, and from a review of other comparable products on the market, we are concerned that the
current choices Avista has made for water heater end use efficiency don’t accurately reflect operational
conditions. While there are indeed HPWH that would be rated at a COP of 0.9 at 5 degrees, these are not
designed to be placed outside and instead reside indoors—in basements, garages, or even utility closets that
stay at room temperature—preventing them from needing to operate in such ambient temperature conditions.
If a customer opts instead to place their water heater outside, they would select a model designed for such
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 737 of 1105
conditions, along the lines of the Sanden model tested by Energy 350 whose observed COP at that temperature
is 1.76. Outdoor placement of water heaters is unusual, and the Sanden split model is more expensive than the
Rheem indoor option, so we would consider the proposed representative water heater the company is
suggesting to be an exceedingly rare configuration on Avista’s system.

For this reason, we request that Avista explain the assumptions the company is making about water heater
locations, the ambient temperatures the model anticipates the water heaters will be exposed to over the course
of a year, and make adjustments to more accurately reflect the product and appliance location choices
customers are likely to make. At a minimum, we consider the current efficiency selected in the August 6th
presentation to represent a circumstance that wouldn’t occur—an indoor model placed outdoors.
Thank you for the opportunity to participate in Avista’s electric Integrated Resource Plan, and for running an
open and inclusive process to date. We look forward to continuing to engage with your IRP team on the
resource plan and this scenario.
Sincerely,

Vlad Gutman-Britten
Washington Director, Climate Solutions
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 738 of 1105
1
Gall, James
From:Gall, James
Sent:Monday, September 14, 2020 10:45 AM
To:Vlad Gutman
Cc:Lyons, John; Pardee, Tom
Subject:RE: [External] RE: Avista Draft TAC 2 Presentations for 8/6/20
Dear Mr. Gutman,

heat pumps
expectations.

After discussion with Avista’s chief energy efficiency engineer, a few modifications to the efficiency calculation are in ord
These modifi
for this calculation on the IRP website. The modifications are as follows:
1) Removed the space heat effect to the efficiency of heat pump water
100%.
2)
customers shut off heat pumps to avoid the defrost cycle.
3) The hybrid scenario begins the load
behavior given economic inputs for fuel.
heaters to clarify the whol
temperatures are high, looking at this v
during periods of cold temperatures at a great ec
such as defrosting, the possibility of a reduction in effi
the regional residential building survey assessment (RBSA) which detail observed performance.

Space Heating Conversion
Fuel conversion from natural gas to electric heating will likely be to a central heat pump instead of a ductless heat pump
system because current natural gas customers already have ducted systems in their
The central system heat pumps are not as efficient as ductless heat pumps because the system must wor
return air, or return air only coming from one floor, can reduce the rated efficiency of the heat pump. With a ductle
all of the airflow characteristics are controlled by the heat pump manufacturer resulting in a more efficient unit.
consumer d
effectively model cold te
of inclement weather and further reduces efficiency.
to the current limitations in these systems described above heat pumps will not achieve similar efficiencies now.
The Regional Technical Forum table shown below identifies residential single-
which given the
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 739 of 1105
2
in heating zone 1 makes it dif
climates like ours.

New homes that would previously include natural gas ducted systems could be ductless heat pumps in the future
discussion continues below.

Ductless Heat Pumps
If a natural gas home converts to a ductless heat pump system (DHP), the whole house would not see a COP in the 3 to 5
range for homes with cold temperatures as commonly advertised by the vendors. Fir
or be supplemented with additional resistance heat to maintain house temperature. Further, most
use this system for the entire house and typically only heat one or two rooms while putting very low cost resistive heating i
smaller rooms and areas of the house not frequently used.
Practically, in colder temperatures, it is possi
heat pumps with slightly better than 1 COP values. The f
consumption is over 5,000 kWhrs. The best study here also shows other fuel influe
efficiency is less than a COP of 1.25.

Water Heating
The data included on heat pump water heating is consistent with Avista’s assumptions. This data does not include the
impact of the heat pump system consuming space heat from the house, when adjusting for this consumption, cold weather
efficiency values are
revised them to not be below 100% as they will be in resistance mode for space heating.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 740 of 1105
3

Thanks again for the questions regarding this scenario it has improved the assumptions and our understanding of the
complexities of electrification,

James Gall
IRP Manager, Avista
509-495-2189

From: Vlad Gutman <[e-mail]>
Sent: Tuesday, August 18, 2020 10:23 AM
To: Gall, James <[e-mail]>
Cc: Lyons, John <[e-mail]>; Pardee, Tom <[e-mail]>
Subject: RE: [External] RE: Avista Draft TAC 2 Presentations for 8/6/20

Attached please find some
though I think they’re checking about whether or not I can provide it to you all. In either case, you can receive the list
from them directly if you become a member.

Thanks again for all your work to date, and I look forward to hearing more this afternoon.

--Vlad

---
Vlad Gutman-Britten
Washington Director
Climate Solutions
206-886-4616

From: Gall, James <[e-mail]>
Sent: Wednesday, August 12, 2020 5:19 PM
To: Vlad Gutman <[e-mail]>
Cc: Lyons, John <[e-mail]>; Pardee, Tom <[e-mail]>
Subject: RE: [External] RE: Avista Draft TAC 2 Presentations for 8/6/20

Please send it when you can. I plan to make any modifications to the assumptions in the next two weeks prior to posting
the data file. After you see the new data file we can discuss more then. This is a more straight forward scenario so it can
be refined later in the process compared to other scenarios.

From: Vlad Gutman <[e-mail]>
Sent: Wednesday, August 12, 2020 4:42 PM
To: Gall, James <[e-mail]>
Cc: Lyons, John <[e-mail]>; Pardee, Tom <[e-mail]>
Subject: RE: [External] RE: Avista Draft TAC 2 Presentations for 8/6/20

We’ve collected some data on what’s available on the market now, vs bleeding edge, that we intend to share with you
for your consideration. I’m going to work up a letter—remind me when would be timely to have it to you by?

---
Vlad Gutman-Britten
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 741 of 1105
4
Washington Director
Climate Solutions
206-886-4616

From: Gall, James <[e-mail]>
Sent: Wednesday, August 12, 2020 4:37 PM
To: Vlad Gutman <[e-mail]>
Cc: Lyons, John <[e-mail]>; Pardee, Tom <[e-mail]>
Subject: RE: [External] RE: Avista Draft TAC 2 Presentations for 8/6/20

Hi Vlad,

COP for heating is probably the closest definition, but not for other appliances which is why we labeled it differently.
Also there are lots of options out there and we attempted to make an estimate of the average customer- not the
bleeding edge of available technology. Given technology change potential, we decided to conduct a scenario with much
higher efficiency ratings in the event. My hope is in the next week or two we will post the spreadsheet of our
assumptions and methodology for this scenario and you can take a look.

From: Vlad Gutman <[e-mail]>
Sent: Wednesday, August 12, 2020 4:14 PM
To: Lyons, John <[e-mail]>; Gall, James <[e-mail]>; Pardee, Tom
<[e-mail]>
Subject: [External] RE: Avista Draft TAC 2 Presentations for 8/6/20

Hi all--

On the electrification scenario assumptions, I just want to ensure I properly understand the inputs you’re using—when
you say “end use efficiency”, you’re referring to the COP of the appliance at that temperature. Is that correct? Not some
other rating I’m not thinking of? Just want to make sure I’m properly understanding the metric.

Thanks,

Vlad

---
Vlad Gutman-Britten
Washington Director
Climate Solutions
206-886-4616

From: Lyons, John <[e-mail]>
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<[e-mail]>; Wenke, Steve <[e-mail]>; Lyons, John
<[e-mail]>; 'Gervais Falkner, Linda' <IMCEAEX-
_O=CORP_OU=Site1_cn=Recipients_cn=[e-mail]>; Ehrbar, Pat <[e-mail]>;
McGregor, Ron <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 742 of 1105
5
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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 743 of 1105
6
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'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; Kimball, Paul <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
Hermanson, Lori <[e-mail]>; Ghering, Amanda <[e-mail]>;
'[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; McDougall, James
<[e-mail]>; '[e-mail]' <[e-mail]>; Gross, John
<[e-mail]>; Fisher, Damon <[e-mail]>; Spratt, Dean
<[e-mail]>; Vlad Gutman <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>
Subject: Avista Draft TAC 2 Presentations for 8/6/20

Hello TAC members,

Here are the draft presentations for Thursday’s joint meeting with the Natural Gas TAC and the call in information for
the meeting.

Thank you,

John Lyons
Avista Corp.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 744 of 1105
7
509-495-8515

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CONFIDENTIALITY NOTICE: The contents of this email message and any attachments are intended solely for the addressee(s) and may contain
confidential and/or privileged information and may be legally protected from disclosure. If you are not the intended recipient of this message or an agent of the intended recipient, or if this message has been addressed to you in error, please immediately alert the sender by reply email and then delete this
message and any attachments.
USE CAUTION - EXTERNAL SENDER
Do not click on links or open attachments that are not familiar.
For questions or concerns, please e-mail [e-mail]
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 745 of 1105
1
Gall, James
From:Tina Jayaweera <[e-mail]>
Sent:Friday, February 26, 2021 4:41 PM
To:Lyons, John; Gall, James; Finesilver, Ryan
Cc:Daniel Hua
Subject:[External] RE: Avista's Draft 2021 Electric IRP
Attachments:Avista 2021 Draft Electric IRP_councilstaff.pdf
Hi Avista team,
Thanks for the opportunity to review the draft 2021 Electric IRP. Council staff appreciate the level of engagement from
are asking for clarification or additional detail. However, one more substantial comment from staff is on the market
price forecast:

Preliminary market price forecasts for the 2021 Power Plan diverge from the pricing regime shown in this draft
IRP. While understanding the underlying cause of that divergence would take a deep dive into our respective AURORA
runs, given our work thus far we would expect that it’s related to allowing AURORA to construct new natural gas
generation outside the Northwest to replace expected retirements in the WECC thermal generation fleet (and the
associated volume of those retirements).

We were given guidance from the Council and from our advisory committees to limit the potential for new natural gas
generation both inside and outside the region. In doing so, we see a wave of solar and wind generation construction
that depresses future market prices substantially lowering them from prices seen today. While this is largely outside of
the control of the region, it presents substantial risk to regional utilities making decisions consistent with market prices
that assume natural gas resources will set the marginal price.

We’d encourage all the utilities in the Northwest, including Avista, to test any IRP-based decisions against an
aggressively low market price forecast. Many things are uncertain about the future of the power system in the
WECC. We would not want to represent any forecast, including our own, as certain. But we do think it’s a risk to
consider and one that will be developing rapidly over the next few years.

While we’re still working on the 2021 Power Plan, we’d be happy to share an AURORA archive file of the work done to
date.

Tina Jayaweera (she/her)
Northwest Power & Conservation Council
503-222-5161

From: Lyons, John <[e-mail]>
Sent: Monday, January 4, 2021 3:20 PM
To: '[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; Kalich, Clint <[e-mail]>; Vermillion, Dennis
<[e-mail]>; Rahn, Greg <[e-mail]>; Gall, James
<[e-mail]>; Wenke, Steve <[e-mail]>; Lyons, John
<[e-mail]>; Ehrbar, Pat <[e-mail]>; McGregor, Ron
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 746 of 1105
2
<[e-mail]>; Coelho, Renee <[e-mail]>; Dempsey, Tom
<[e-mail]>; Bryan, Todd <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; Shane, Xin <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; Soyars, Darrell <[e-mail]
<[e-mail]>; Miller, Joe <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; Kimmell, Paul
<[e-mail]>; Lee, Lisa <[e-mail]>; Tatko, Mike <[e-mail]>;
Trabun, Steve <[e-mail]>; Vincent, Steve <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; Forsyth, Grant <[e-mail]>; Bonfield, Shawn
<[e-mail]>; Steven Simmons <[e-mail]>; Steiner, Nolan
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; Maher, Patrick
<[e-mail]>; Kinney, Scott <[e-mail]>; Thackston, Jason
<[e-mail]>; Holland, Kevin <[e-mail]>; Rothlin, John
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; McClatchey, Erin <[e-mail]>;
Elizabeth Osborne <[e-mail]>; Gillian Charles <[e-mail]>;
'[e-mail]' <[e-mail]>; Fielder, Casey <[e-mail]>;
Kacalek, Sean <[e-mail]>; Browne, Terrence <[e-mail]>;
'[e-mail]' <[e-mail]>; Sprague, Collins
<[e-mail]>; '[e-mail]' <[e-mail]>; Schlect, Jeff
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; Howard, Bruce <[e-mail]>; Magalsky, Kelly
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>; Andrea, Michael
<[e-mail]>; '[e-mail]' <[e-mail]>; Tina Jayaweera
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>; Dillon,
Mike <[e-mail]>; '[e-mail]' <[e-mail]>; Pardee, Tom
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; Finesilver, Ryan
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; Schuh, Karen
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]'
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 747 of 1105
3
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; Schultz, Kaylene
<[e-mail]>; '[e-mail]' <[e-mail]>; Tyrie, Mary
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; Rose, Melanie <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; Brown, Garrett
<[e-mail]>; Ericksen, Ryan <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; Kimball, Paul
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; Hermanson, Lori <[e-mail]>; Ghering, Amanda
<[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>;
McDougall, James <[e-mail]>; '[e-mail]' <[e-mail]>; Gross, John
<[e-mail]>; Fisher, Damon <[e-mail]>; Spratt, Dean
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; Daniel Hua <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>;
Brandon, Annette <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; Majure, Jaime <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>
Subject: Avista's Draft 2021 Electric IRP

Hello TAC Members,

Attached is a copy of the draft 2021 Electric IRP for your review. Please provide any comments or edits back to us by
Monday, March 1, 2021 to me at [e-mail]. The final IRP and completed appendices will be filed on
April 1, 2021 with the Idaho and Washington Commissions.

Our fifth and final TAC meeting will be held on Thursday, January 21, 2021. The meeting invitation and agenda will be
available by the end of this week. There will also be an opportunity to provide written comments about the draft IRP to
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 748 of 1105
4
the Washington Commission and a public meeting on February 23, 2020. We will provide more details at the fifth TAC
meeting.

Thank you for all of your participation in the 2021 IRP,

John Lyons
Avista Corp.
509-495-8515

CONFIDENTIALITY NOTICE: The contents of this email message and any attachments are intended solely for the addressee(s) and may contain
confidential and/or privileged information and may be legally protected from disclosure. If you are not the intended recipient of this message or an agent
of the intended recipient, or if this message has been addressed to you in error, please immediately alert the sender by reply email and then delete this message and any attachments.
USE CAUTION - EXTERNAL SENDER
Do not click on links or open attachments that are not familiar.
For questions or concerns, please e-mail [e-mail]
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 749 of 1105
Northwest Power and Conservation Council
In line comments on draft Electric IRP

Page 13: See comment in email re: suggestion to do sensitivity study with significantly
lower market prices
Page 16: DR capability is for summer or winter or either?
Page 16: In section 5, the target EE is 113 aMW
Page 57: Be more clear which climate trend you are using from the Council, as we have
several projected futures
Page 66: Is there any analysis of how climate change will affect hydro availability on a
monthly basis?
Page 87: Also, the achievable technical potential includes a max achievability. Did the
CPA use the 7P or the 2021P assumptions?
Page 88: I read this that AEG didn't use the RBSA, which is fine if Avista has sufficient
res data, but it would be good to explain this. Also, since CBSA is regional, how was it
downscaled to Avista. Perhaps this is in the CPA report?
Page 89: I don't understand this sentence
Page 90: How are these adjusted? Since the 2021P starts in 2022, what recent
accomplishments would be incorporated?
Page 90: I think this is a bit confusing - i would recommend breaking out the "ramp rate"
from the "achievability factor", since the 85- 100% is not really the ramp rate
Page 91: Incorrect units
Page 91: Typo in figure "cumulative". Also, the terminology is getting confusing here,
you mean achievable *economic* potential, right?
Page 92: It's a little confusing that this chart goes to 2045, while the above table is
through 2041. Add a sentence in paragraph above about that?
Page 93: 2022-2023, right?
Page 94: If this is utility cost, not total cost, then what assumption was made for portion
of total cost made for by the utility?
Page 97: I'm not sure what this is referencing. The methodology we recommend uses 5-
10 years historic and/or forward-looking, data available. What is this referencing?
Page 97: Non-energy impacts could be benefits or costs
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 750 of 1105
Page 97: There is also language in the report about how these values should not be
used past 2022.
Page 98: Given how Avista's generation supply is getting cleaner over the IRP time
horizon, is that incorporated into this analysis?
Page 98: Has applying the 10% credit for Idaho been discussed?
Page 107: I'm confused about the numbers in this bullet compared to the bullet above
that indicates the TOU opt-in has a 4.3 MW potential
Page 109: Are these costs net of anything? e.g. T&D deferrals? How are incentives
treated? It would be helpful to have a brief discussion of what is included in the levelized
cost calcs.
Page 109: It might be nice to have these presented in order of increasing cost?
Page 111: 8 continuous hours? That is quite long for a DR program
Page 120: How is this price determined?
Page 172: How are you incorporating other states (mostly CA) clean energy policies?
Page 179: It's not clear if/how REC prices are being incorporated
Page 193: Since renewables have zero emissions, it seems that they would be more
often built in a SCC world, and thus there would be less interaction between the thermal
plant and the market price.
Page 194: It is not intuitive why there would be less wind in the SCC scenario
Page 229: I think this is an overly pessimistic view of HPs. Newer units that are installed
well with good controls can certainly provide a capacity benefit. I see later you explore
the impact of higher efficiency units which is good. This leads me to think the Avista EE
program should be focused more on ensuring installed ASHP are operating optimally

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 751 of 1105
1
Gall, James
From:Gall, James
Sent:Monday, March 1, 2021 12:01 PM
To:Tina Jayaweera; Lyons, John; Finesilver, Ryan
Cc:Daniel Hua; Kalich, Clint
Subject:RE: [External] RE: Avista's Draft 2021 Electric IRP
Hi Tina and Dan,

Thank you for the review of our document. I’ve conducted a quick look at your comments and it appears you spend
regarding the price forecast. I have concerns that prices going forward will be extremely volatile, more than Aurora can
quantify, much of this volatility will depend on how much and if capacity resources will be developed or not- I also think
its appropriate to understand the risk of higher and lower prices. From my work in the short term, Avista’s price
forecasts are too low- specifically not including risk premiums we are seeing from resource adequacy issues we are
seeing. Although, in the long run there is significant downward risk with more renewables- I guess this future will
depend on how far policy makers will take goals and ambitions to actual operations and construction.

There will also likely be a feedback loop as well- such as changes in loads (both industrial losses and electrification
opportunities and political changes due to ramifications of policy changes) and storage opportunities. I think storage
could be key in keeping prices from getting too low- but that will depend on future costs of that technology. I guess
where I’m going is there is a number of paths the future may take us and its really an issue of how much time should we
make to look at the region versus our portfolio.

The way things are trending I would say more focus is going toward our portfolio. In this case the real risk of having too
low of forecast for prices could have an effect of less acquisition of EE, but in the end with our requirements of having
clean energy and capacity- the price forecast really only impacts a solar vs wind decision- but so far wind is winning that
decision due to capacity requirements and over reliance of solar elsewhere; then they question of should we build
natural gas or storage-
pondering for some time do price forecasts really matter for resource planning- given we have fewer resources to
choose from and specific requirements to meet. For example, the energy price used to be a major component of our EE
avoided cost- now the highest component is social cost of carbon and non-energy benefits- its seems the world has
shifted from energy price forecasts.

Thanks for raising this important issue.

James

From: Tina Jayaweera <[e-mail]>
Sent: Friday, February 26, 2021 4:41 PM
To: Lyons, John <[e-mail]>; Gall, James <[e-mail]>; Finesilver, Ryan
<[e-mail]>
Cc: Daniel Hua <[e-mail]>
Subject: [External] RE: Avista's Draft 2021 Electric IRP

Hi Avista team,
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 752 of 1105
2
Thanks for the opportunity to review the draft 2021 Electric IRP. Council staff appreciate the level of engagement from
are asking for clarification or additional detail. However, one more substantial comment from staff is on the market
price forecast:

Preliminary market price forecasts for the 2021 Power Plan diverge from the pricing regime shown in this draft
IRP. While understanding the underlying cause of that divergence would take a deep dive into our respective AURORA
runs, given our work thus far we would expect that it’s related to allowing AURORA to construct new natural gas
generation outside the Northwest to replace expected retirements in the WECC thermal generation fleet (and the
associated volume of those retirements).

We were given guidance from the Council and from our advisory committees to limit the potential for new natural gas
generation both inside and outside the region. In doing so, we see a wave of solar and wind generation construction
that depresses future market prices substantially lowering them from prices seen today. While this is largely outside of
the control of the region, it presents substantial risk to regional utilities making decisions consistent with market prices
that assume natural gas resources will set the marginal price.

We’d encourage all the utilities in the Northwest, including Avista, to test any IRP-based decisions against an
aggressively low market price forecast. Many things are uncertain about the future of the power system in the
WECC. We would not want to represent any forecast, including our own, as certain. But we do think it’s a risk to
consider and one that will be developing rapidly over the next few years.

While we’re still working on the 2021 Power Plan, we’d be happy to share an AURORA archive file of the work done to
date.

Tina Jayaweera (she/her)
Northwest Power & Conservation Council
503-222-5161

From: Lyons, John <[e-mail]>
Sent: Monday, January 4, 2021 3:20 PM
To: '[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; Kalich, Clint <[e-mail]>; Vermillion, Dennis
<[e-mail]>; Rahn, Greg <[e-mail]>; Gall, James
<[e-mail]>; Wenke, Steve <[e-mail]>; Lyons, John
<[e-mail]>; Ehrbar, Pat <[e-mail]>; McGregor, Ron
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; Coelho, Renee <[e-mail]>; Dempsey, Tom
<[e-mail]>; Bryan, Todd <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; Shane, Xin <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; Soyars, Darrell <[e-mail]
<[e-mail]>; Miller, Joe <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; Kimmell, Paul
<[e-mail]>; Lee, Lisa <[e-mail]>; Tatko, Mike <[e-mail]>;
Trabun, Steve <[e-mail]>; Vincent, Steve <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 753 of 1105
3
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; Forsyth, Grant <[e-mail]>; Bonfield, Shawn
<[e-mail]>; Steven Simmons <[e-mail]>; Steiner, Nolan
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; Maher, Patrick
<[e-mail]>; Kinney, Scott <[e-mail]>; Thackston, Jason
<[e-mail]>; Holland, Kevin <[e-mail]>; Rothlin, John
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; McClatchey, Erin <[e-mail]>;
Elizabeth Osborne <[e-mail]>; Gillian Charles <[e-mail]>;
'[e-mail]' <[e-mail]>; Fielder, Casey <[e-mail]>;
Kacalek, Sean <[e-mail]>; Browne, Terrence <[e-mail]>;
'[e-mail]' <[e-mail]>; Sprague, Collins
<[e-mail]>; '[e-mail]' <[e-mail]>; Schlect, Jeff
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; Howard, Bruce <[e-mail]>; Magalsky, Kelly
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>; Andrea, Michael
<[e-mail]>; '[e-mail]' <[e-mail]>; Tina Jayaweera
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>; Dillon,
Mike <[e-mail]>; '[e-mail]' <[e-mail]>; Pardee, Tom
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; Finesilver, Ryan
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; Schuh, Karen
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; Schultz, Kaylene
<[e-mail]>; '[e-mail]' <[e-mail]>; Tyrie, Mary
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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 754 of 1105
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Subject: Avista's Draft 2021 Electric IRP

Hello TAC Members,

Attached is a copy of the draft 2021 Electric IRP for your review. Please provide any comments or edits back to us by
Monday, March 1, 2021 to me at [e-mail]. The final IRP and completed appendices will be filed on
April 1, 2021 with the Idaho and Washington Commissions.

Our fifth and final TAC meeting will be held on Thursday, January 21, 2021. The meeting invitation and agenda will be
available by the end of this week. There will also be an opportunity to provide written comments about the draft IRP to
the Washington Commission and a public meeting on February 23, 2020. We will provide more details at the fifth TAC
meeting.

Thank you for all of your participation in the 2021 IRP,

John Lyons
Avista Corp.
509-495-8515

CONFIDENTIALITY NOTICE: The contents of this email message and any attachments are intended solely for the addressee(s) and may contain
confidential and/or privileged information and may be legally protected from disclosure. If you are not the intended recipient of this message or an agent of the intended recipient, or if this message has been addressed to you in error, please immediately alert the sender by reply email and then delete this
message and any attachments.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 755 of 1105
5
USE CAUTION - EXTERNAL SENDER
Do not click on links or open attachments that are not familiar.
For questions or concerns, please e-mail [e-mail]
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 756 of 1105
February 5, 2021
Mark Johnson
Executive Director and Secretary
Washington Utilities and Transportation Commission
621 Woodland Square Loop SE
Lacey, WA 98504-7250
RE: Comments of Renewable Northwest, Docket UE-200301
Utilities and Transportation Commission’s January 5, 2021, Notice of Opportunity to File
Written Comments Relating to Avista’s 2021 Draft Integrated Resource Plan for
Electricity, Docket UE-200301.
I. INTRODUCTION
Renewable Northwest thanks the Washington Utilities and Transportation Commission (“the
Commission”) for this opportunity to comment in response to the Commission’s January 5,
2021, Notice of Opportunity (“Notice”) to File Written Comments relating to Avista Corporation
d/b/a Avista Utilities’ (“Avista” or “the Company”) 2021 Draft Integrated Resource Plan (“Draft
IRP”) for Electricity, published January 4, 2021.
Renewable Northwest participated in Avista’s Technical Advisory Committee (“TAC”) meetings
during development of the Draft IRP, and we were generally pleased with the Company’s
consideration of stakeholder input during its public participation phase. Still, we have noted in
these comments various areas for improvement in the Draft IRP for Avista and the Commission
to consider, bearing in mind the important role of this IRP to plan for compliance with the clean
energy standards of Washington’s Clean Energy Transformation Act (“CETA”), and as such, to
inform Avista’s first Clean Energy Implementation Plan (“CEIP”), set to be published later this
year. 1
In these comments, we identify areas where Avista’s Draft IRP does not align with the most
current resource costs and characteristics. We offer recommendations for revising Avista’s
flexibility analysis, resource adequacy considerations, and sensitivity analyses with the goal of
nudging the Company toward a least-cost portfolio with the best likelihood of meeting CETA’s
clean energy standards.
1 WAC 480-100-640
Feb. 5, 2021 Comments of Renewable Northwest, Docket UE-200301 Page 1 of 8
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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 757 of 1105
Finally, we appreciate Avista’s commitment to achieving carbon neutrality in its electric
operations by 2027 and to provide customers with one hundred percent carbon-free electricity by
2045. We think the Company is making strides in creating a path toward meeting those goals, 2
but we urge Avista and the Commission to consider where the Draft IRP may be hindered by
traditional resource planning assumptions not relevant to an energy transformation toward a
dynamic mix of non-emitting resources. We look forward to continued participation in the
development of Avista’s 2021 IRP.
II. COMMENTS

A.Regulatory Context

CETA broadly requires Washington utilities to achieve greenhouse gas neutrality by 2030 and to
serve Washington customers with one hundred percent non-emitting and renewable electricity by
2045. Utilities must identify steps to achieve these standards using the new tool of Clean Energy 3
Implementation Plans, and those CEIPs must in turn “identify specific actions to be taken by the
investor-owned utility over the next four years, ​consistent with the utility's long-range integrated
resource plan​ and resource adequacy requirements, that demonstrate progress toward meeting
the standards under RCW 19.405.040(1) and 19.405.050(1)” as well as interim targets to ensure
incremental progress. 4

The Commission worked for months with many stakeholders, including Renewable Northwest,
to craft new rules aligning utility IRPs with CEIPs and CETA’s substantive requirements. These
new rules point to some key downstream effects of IRPs: first, “[t]he commission will consider
the information reported in the integrated resource plan when it evaluates the performance of the
utility in rate and other proceedings” ; and second, a utility’s “CEIP must describe how [its] 5
specific actions ... [a]re consistent with the utility's integrated resource plan.” The main 6
takeaway of this structure is that it is important to get as much correct as possible in the IRP, as
analytical missteps could have repercussions both for utility cost recovery and for achieving
CETA’s critically important substantive standards.

With that backdrop in mind, we offer the following comments on Avista’s Draft IRP, assessing
elements of the Draft IRP not only against specific provisions of the Commission’s rules as
2 Avista Connections, ​available at
https://www.myavista.com/connect/articles/2019/08/this-is-clean-energy-for-the-future​.
3 RCW 19.405.040(1) & 19.405.050(1) (emphasis added).
4 RCW 19.405.060(1)(b)(iii).
5 WAC 480-100-238(6).
6 WAC 480-100-640(6)(d).
Feb. 5, 2021 Comments of Renewable Northwest, Docket UE-200301 Page 2 of 8
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 758 of 1105
appropriate, but also against the broader context of how the information in this IRP will be used
in future planning, procurement, and ultimately cost recovery efforts.

B.Supply Side Resource Options

Assumptions

Avista may have rounded up its solar capital costs, judging by current estimates, but the
Company should consider revising its solar capital costs to reflect the slightly lower values
estimated at this time. For example, Lazard’s Levelized Cost of Energy Analysis for 2020
estimates solar capital costs to lie in the range of $825 to $975. 7

Considering Avista’s assumptions for lithium-ion battery storage, we recommend the Company
review the data informing the levelized cost ($/kW) for the preferred 4-hour lithium-ion battery,
as there appears to be a gradual price increase after 2033 rather than a steady decline, which
would be expected. For example, the National Renewable Energy Laboratory’s (“NREL”) 2020 8
Annual Technology Baseline (“ATB”) reports a trend of cost reductions (illustrated as $/kW in
Figure 1​) through to 2050.

Figure 1.​ Li-ion battery storage projection (in $/kW) from NREL’s Annual Technology Baseline 2020. 9

7 ​See, e.g.​, Lazard’s Levelized Cost of Energy Analysis (Oct. 2020), at 11, ​available at
https://www.lazard.com/media/451419/lazards-levelized-cost-of-energy-version-140.pdf​.
8 Table 9.7. Lithium-ion Levelized Cost $/kW, p. 9-14
9 Battery Storage cost values from W. Cole and A. W. Frazier, “Cost Projections for Utility-scale Battery Storage:
2020 Update,” NREL/TP-6A20-75385. Golden, CO: National Renewable Energy Laboratory, ​available at
https://www.nrel.gov/docs/fy20osti/75385.pdf​.
Feb. 5, 2021 Comments of Renewable Northwest, Docket UE-200301 Page 3 of 8
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 759 of 1105

Ancillary Services Value
We appreciate Avista’s proactive approach in valuing ancillary services of emerging resources
using sub-hourly modeling. Because there are a number of impending questions that the
Company is working through, the comments provided below will shed some light on the broader
concept of system flexibility and how emerging resources are able to provide the flexibility
needs arising from an increasing share of renewable resources in a reliable manner.

Flexibility has always been part of power system operation because the normal demand for
electricity varies significantly on a daily and seasonal basis. Traditional approaches to planning
have supported flexibility that is sufficient to meet load reliably. However, increasing renewable
generation sources may make traditional approaches to planning inadequate to ensure sufficient
flexibility. System flexibility can be characterized along four dimensions: first, the ​absolute
power output capacity​ range (in “MW”); second, the​ ​speed of power output change​, or ramp
rate (in “MW/min”); third, the ​duration of energy levels​ ​(in “MWh”); and finally the ​carbon
intensity​ ​(in “CO​2​e/MWh”). Resources which have a larger range between their minimum and
maximum “MW” output, such as pumped-hydro storage systems, can provide the flexibility to
adjust to a wider range of power system conditions. Resources that can change their output
quickly or can be easily turned on or off, including 2-, 4- & 6-hour lithium-ion, flow battery
storage systems and demand response (“DR”), have a higher ramp rate and are more flexible
because they adjust faster to changes in power system conditions. Resources which can deliver
energy for longer durations increase flexibility because they can address prolonged disturbances
or outages. Resources such as conventional combustion turbines and combined cycle can provide
dispatchable power but have low capacity utilization and are emission-intensive when ramped up
or down rapidly. These different dimensions are important to consider in any holistic flexibility
analysis and, thus, in calculating benefits, considering not just the frequency of flex violations
but their magnitude, speed, duration, and carbon intensity.

In addition to the ADSS system, we recommend the use of the PLEXOS model to simulate
generation on a sub-hourly timescale to calculate the balancing reserve requirements and the
associated system costs and benefits to meet those intra-hourly dispatch requirements, as legally
enforced through NERC’s BAL series standards. As defined in BAL-005.5, each Balancing
Authority Area is required to have Automatic Generation Control (“AGC”), calculate Area
Control Error (“ACE”), and deploy balancing reserves to balance resources and demand. It is
important to recognize that with the changing supply-and-demand paradigm, flexibility needs are
changing as system variability migrates from load to generation. With Avista’s participation in
the Energy Imbalance Market (“EIM”), it has the ability to tap into the diversity benefits of
multiple resources to balance their demand and supply.

Feb. 5, 2021 Comments of Renewable Northwest, Docket UE-200301 Page 4 of 8
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 760 of 1105
At the same time, new technologies (such as controllable solar and wind power plants, battery
storage systems, pumped-hydro systems, and demand response resources) and operational
practices provide new options for flexibility. These emerging needs and solutions increase the
benefit of a transparent flexibility value, which can help system operators efficiently maintain
reliability and enable market participants to make informed investments. Controllable solar and
wind power plants have the ability to respond to dispatch instructions much more quickly than
conventional generators, in addition to having a zero variable cost. “Flexible solar” not only
contributes to solving operating challenges related to solar variability but can also provide grid
services, essentially creating dispatchable renewable power plants. A similar study was 10
conducted by Avangrid, NREL, and GE showing that a utility-scale wind power plant can
provide regulation-up, regulation-down, and other grid services. Since the flexibility benefit is 11
calculated based on the difference between “day-ahead” and “intra-hour” dispatch, resources
with zero variable cost and fast response times, like controllable renewable, battery storage,
demand response and pumped-hydro, would generate much higher values than conventional
thermal resources. In addition, it has also been proven through many studies that geographical 12
resource diversity and aggregation reduce the need for reserve requirements by reducing
short-term variability. 13

In conclusion, we appreciate the effort Avista has put into modeling ancillary services and
providing draft results to stakeholders, but we recommend additional considerations to (i)
operational flexibility (both up & down) offered by controllable solar and wind power plants, (ii)
detailed analysis of multiple lithium-ion battery durations to the flexibility resource options, (iii)
the modeling of sensitivities around the nameplate capacity of flexible resources, and (iv) the
draft value of “diversity savings” from participation in the EIM. In addition, it would be useful to
see different dimensions of the flex violations and how they are being addressed using the fleet
of resources modeled in the flex analysis conducted using PLEXOS. We are also interested to
view the flex benefit results coming out of the modeling for pumped-hydro and DR resources,
which we believe would be higher than conventional solutions to provide the necessary
intra-hourly supply and load flexibility.

Resource ELCC Analysis
10 Investigating the Economic Value of Flexible Solar Power Plant Operation First Solar & E# Study. October 2018.
https://www.ethree.com/wp-content/uploads/2018/10/Investigating-the-Economic-Value-of-Flexible-Solar-Power-Pl
ant-Operation.pdf
11 Avangrid Renewables: Demonstration of Capability to Provide Essential Grid Services..
http://www.caiso.com/Documents/WindPowerPlantTestResults.pdf
12 Determining Utility System Value of Demand Flexibility From Grid-interactive Efficient Buildings.
https://pubs.naruc.org/pub/2E1DDEEC-155D-0A36-3137-0FC3D941B1A4
13 Ancillary Service and Balancing Authority Area Solutions to Integrate Variable Generation. Available at:
https://www.nerc.com/files/ivgtf2-3.pdf

Feb. 5, 2021 Comments of Renewable Northwest, Docket UE-200301 Page 5 of 8
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 761 of 1105
While we appreciate the detailed analysis that Avista has conducted and the provision of peak
capacity credit values for different supply side resource options, we are concerned that these
values significantly under value storage and hybrid resources.

To start, the Draft IRP references an E3 report in stating that, “4-hour duration storage can
provide high levels of resource adequacy in small quantities because it has other resources to
assist in its re-charging; but as its proportion gets larger, there is not enough energy to refill the
storage device for later dispatch.” This statement is confusing and misrepresents operating 14
characteristics and values of energy storage systems. As we know, reliability should be valued
during the times when the system is in stress (i.e. hours with the highest probability of loss of
load). As Avista mentions, 4-hour duration storage can provide high levels of resource adequacy.
The quantity of adequacy depends on the operating characteristics of the power plant and how it
is being operated to meet the reliability risks. In addition, storage capacity can be easily refilled
during off-peak hours when solar and wind are usually curtailed (mid-morning for solar and late
night for wind), either directly or indirectly, from the grid. It is also worth noting that hybrid
resources are not physically restricted to charge from the renewable component since the Federal
Investment Tax Credit (ITC) is a financial not a physical restriction. Thus, a power plant
operator may choose to charge the storage partially from the grid to ensure that it meets the
capacity requirement during critical periods.

The Draft IRP also mentions that “[h]igher levels of penetrations for renewables may lower their
effect on resource adequacy.” While this statement is true due to diminishing marginal ELCC
from increasing penetration of renewables, it is also true that the capacity credit of storage
increases with increasing penetration of renewables since they are complementary resources, by
changing the shape of net demand patterns and effectively shifting delivery of energy to meet the
reliability needs. An analysis conducted by Astrape Consulting commission by joint IOUs in 15
California showed that solar paired with 4-hour storage provides greater than 95% ELCC on
average including analysis and values pertaining to the BPA region. Avista’s value provided in 16
Table 9.12 shows a 17% value which is extremely low based on recent IRP filings and technical
reports in the region. Therefore, we recommend Avista study for its final IRP the different
operational configurations and characteristics of hybrid resources and standalone storage to
correctly evaluate the resource ELCC value.

14 P. 9-27
15 The Potential for Battery Energy Storage to Provide Peaking Capacity in the United States. Denholm et al, 2019.
Available at:
https://www.osti.gov/biblio/1530173-potential-battery-energy-storage-provide-peaking-capacity-united-states
16 2020 Joint CA IOU ELCC Study Report 1. Astrape Consulting. August 2020. Available at:
https://www.astrape.com/2020-joint-ca-iou-elcc-study-report-1/
Feb. 5, 2021 Comments of Renewable Northwest, Docket UE-200301 Page 6 of 8
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 762 of 1105
C.Preferred Resource Strategy

To begin, we request that Avista incorporate the results of its 2020 Renewable RFP in the
preferred resource strategy (“PRS”) for its final IRP, including how Avista’s improved
knowledge of current market prices may adjust resource assumptions informing the 2021 IRP
model.

We appreciate Avista’s transparency in revealing that the early economic contractual exit from
Colstrip Units 3 & 4 would benefit its Washington and Idaho customers. If the joint owners of
this resource were to agree on the terms of early exit from or retirement of these units, it would
in part be because of this modeling effort by Avista. However, we recognize the complexity of
exiting a jointly-owned resource, and we understand Avista’s decision to maintain the 2025
Colstrip exit date in its PRS.

As indicated above, Avista may be undervaluing storage and hybrid resources, especially
considering Washington’s and the entire region’s transition away from fossil resources, thus
increasing the penetration of renewables on the grid and the capacity credit of storage. Avista
does note their intention to study additional benefits of storage by modeling additional scenarios
including price and renewable penetration. We hope Avista will conduct these analyses to 17
inform the PRS of the final IRP, as we urge the Company and the Commission to acknowledge
that traditional methods of resource planning -- especially those driving standards for
determining resource adequacy -- will likely continue to favor new natural gas builds and delay
the clean energy transition.

Avista mentions throughout the Draft IRP that upon exit from coal contracts by 2025, limited
capacity options are available as replacement. For example, Avista notes, “With the exit of
Colstrip and the expiration of the Lancaster PPA in the fall of 2026, the PRS adds 211 MW of
natural gas-fired CTs. The 2020 IRP assumed the capacity lost from Colstrip and Lancaster
could be met with long duration pumped hydro, but the updated cost and construction schedule
information for pumped hydro caused this resource to not be selected in this IRP.” For the 18
Commission and stakeholders to better understand why Avista’s capacity needs can only be met
with new natural gas peaking capacity, we recommend that Avista provide at its upcoming TAC
meeting or publish in its final IRP a projected loss-of-load event, displaying by hour where there
is a deficiency in available capacity. This could be in the form of a 12x24 matrix of the peak
demand or hours with the highest loss of load probability which were used to calculate the ELCC
values for all resources. 19
17 P. 9-26
18 P. 11-5
19 ​See, e.g.,​ Energy+Environmental Economics (E3), “Capacity Value Framework & Allocation Options,” Oregon
Feb. 5, 2021 Comments of Renewable Northwest, Docket UE-200301 Page 7 of 8
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 763 of 1105

D.Portfolio Scenario Analysis

While there is certainly value in many of Avista’s twenty modeled sensitivities, we recommend
the Company conduct one additional analysis to better understand how policy-driven changes in
Avista’s resource mix should impact the way the Company plans for meeting demand reliably
and at least cost. For example, especially considering our previous comments regarding pricing
and ELCC values for storage resources, a sensitivity analysis of must-take storage (not limited
by resource type or duration characteristics) combinations in place of new natural gas peaking
plants would inform Avista how much current storage technologies would change levelized
portfolio costs. Avista’s Portfolio #5 -- “Clean Resource Plan (2027)” -- does not prohibit new
gas procurements, and Portfolio #6 -- “Clean Resource Plan (2045)” -- does prohibit new gas
procurements but curiously allows Colstrip to exit at any time. 20
III. CONCLUSION

Renewable Northwest thanks Avista and the Commission for its consideration of this feedback.
We are optimistic that the changes and additional analysis we have recommended above will
help Avista to identify a least-cost portfolio that also puts the Company on a path to achieving
CETA’s clean energy standards and the company’s own emission reduction goals. We look
forward to continued engagement as a stakeholder in this 2021 IRP process.

Sincerely,

Public Utilities Commission (UM 2011) at slide 39 (Jul. 9, 2020), ​available at
https://edocs.puc.state.or.us/efdocs/HAH/um2011hah17397.pdf​.
20 P. 12-6
Feb. 5, 2021 Comments of Renewable Northwest, Docket UE-200301 Page 8 of 8
/s/ Katie Ware
Katie Ware
Washington Policy Manager
Renewable Northwest
[e-mail]
/s/ Sashwat Roy
Sashwat Roy
Technology & Policy Analyst
Renewable Northwest
[e-mail]
/s/ Max Greene
Max Greene
Regulatory & Policy Director
Renewable Northwest
max​@renewablenw.org
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 764 of 1105
February 5, 2021 Puget Sound Energy 355 110th Ave NE Bellevue, WA 98004 RE: Comments of Swan Lake and Goldendale Avista Corporation – Draft Integrated Resource Plan UTC Docket UE-200301
The companies working to develop the Swan Lake and Goldendale pumped hydro storage
projects (“Swan Lake and Goldendale”) appreciate Avista Corporation’s (“Avista”) work that
went into preparing its draft Integrated Resource Plan (“Draft IRP”), which was filed in the
above-referenced proceeding on January 4, 2021. The Washington Utilities and Transportation
Commission (“Commission”) subsequently issued a notice, on January 5, 2021, indicating it
would accept comments on Avista’s Draft IRP until February 5, 2021.1 In response to that
notice, Swan Lake and Goldendale are filing these comments.

These comments advocate for Avista to further consider pumped storage resources instead of new
natural gas facilities, which are politically infeasible to build and do not align with Washington
State’s Clean Energy Transformation Act (“CETA” requirements. Specifically, these comments:
(1) seek further information regarding Avista’s modeling and assumptions for pumped storage; (2) argue that Avista should not seek to construct new gas facilities, given the current political realities associated with new gas facilities and CETA’s requirements; and (3) advocate for Avista to issue a capacity request for proposals (“RFP”) as soon as possible, as an RFP is the only mechanism through which Avista will receive accurate pricing and capacity proposals, particularly for large resources like pumped storage.
I. Overview of Pumped Storage in the Draft IRP

According to Avista’s Draft IRP, long duration pumped hydro storage was identified as the capacity resource to meet future long duration deficits; however, it appears the Draft IRP did not include them in the Preferred Resource Strategy because “long duration pumped hydro is likely available later than the timelines used in the 2020 IRP and at higher costs.”2 As a result, the Draft IRP states, “The resource analysis identifies a natural gas CT to replace resource deficits if pumped hydro is not a feasible resource to meet the 2026 shortfall.”3 These statements suggest that pumped storage was Avista’s preferred resource, if not for a mismatch in timing and updated cost figures.
1 Notice of Opportunity to File Written Comments, Docket UE-200301, Jan. 5, 2021, available at: https://www.utc.wa.gov/_layouts/15/CasesPublicWebsite/GetDocument.ashx?docID=11&year=2020&docketNumber=200301. 2 Draft IRP at 14-5. 3 Id.
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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 765 of 1105
Through these comments, Swan Lake and Goldendale suggest that Avista reconsider including pumped storage in its Preferred Resource Strategy. Specifically, as further explained below, Swan Lake and Goldendale are two of the most mature projects in the region, one of which (Swan Lake) is likely to be available in 2026, which matches Avista timeline of capacity need. Furthermore, Swan Lake and Goldendale are in the process of refining their cost assumptions and, should Avista issue an RFP, would likely be able to provide update cost figures that may make pumped storage a more attractive option, particularly considering the infeasibility of constructing a new natural gas plant, as explained below.
II. Swan Lake and Goldendale Request Further Information on Avista’s Modeling Assumptions for Pumped Storage Swan Lake and Goldendale appreciate that Avista has been forthcoming with a significant amount of data that was used to develop the Draft IRP. That said, Swan Lake and Goldendale request Avista provide some additional information and data on the modeling assumptions used for the various pumped storage resources considered in the Draft IRP. Specifically, Swan Lake and Goldendale request further information regarding: (1) the “state of charge” assumed by Avista in order to develop its capacity values for pumped storage, as seen in Table 9.12; (2) what duration Avista assumed for the useful life of a pumped storage project; and (3) whether Avista’s analysis of pumped storage considered the Swan Lake project specifically, which is expected to be available in 2026 and, therefore, aligns with Avista’s capacity need.
a. Swan Lake and Goldendale Request Further Information on Avista’s Modeling Assumptions Regarding a Pumped Storage Project’s State of Charge Swan Lake and Goldendale believe one of the impediments to long-duration pumped storage performing even better in Avista’s Draft IRP is the very low capacity values being assigned to pumped storage resources. For example, Table 9.12 indicates an 8-hour pumped storage project would only contribute 30% to Avista’s peak capacity need, and even a 12-hour project would contribute only 58%.4 Considering these figures are much lower than Swan Lake and Goldendale would expect, and drastically lower than those used by other utilities in the Pacific Northwest,5 Swan Lake and Goldendale request that Avista provide further information regarding the assumed “state of charge” for these resources. Swan Lake and Goldendale assume the “state of charge”
assumptions are the genesis for these low figures.

If the highest priority for pumped storage is reliability, then Avista would always have the ability
to charge it for its longest available durations, eight hours or more. Understanding that Avista will
always prioritize reliability over economic optimization, adjustments to the state of charge
modeling may be appropriate. Swan Lake and Goldendale believe that Avista’s model may be
using a very low state of charge entering into the next operating day for pumped storage (possibly
as low as 20% pond fill); however, this planning assumption does not align with the operational
4 Id. at 9-28, Table 9.12. 5 Swan Lake and Goldendale would also note for the Commission’s benefit that both PacifiCorp and Portland General Electric use capacity contribution figures in the range of 80-95% for pumped storage in their respective IRPs.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 766 of 1105
realities associated with operating hydro or pumped storage facilities. Operationally, peak load days are fairly predictable, meaning that Avista’s operations folks would set up for those days in advance to ensure its hydro (or pumped storage) facilities have sufficient pond fills to cover the expected peak load hours. Furthermore, the pumped hydro facility would not necessarily need to deplete its full reservoir daily to address capacity needs (low frequency of 8-hour reliability events), reducing the total amount of charging required to address all potential loss of load events. A low capacity contribution value (ELCC) for pumped hydro implies that the facility is energy limited and does not have access to the market or other on-system resources to charge for peak load events. Swan Lake and Goldendale understand that Avista may be concerned about the evolving market for peak import assumptions during the winter, given the emerging regional capacity shortage documented in several NWPCC studies. However, import assumptions during
off-peak hours in the winter should be re-visited, given that these would be key hours when long-
duration storage would charge for the winter on-peak reliability. Additionally, if not already doing
so, Swan Lake and Goldendale recommend that Avista consider optimizing the dispatch of their
resources over a wider time window (1-2 weeks). A wider optimization time window in resource
adequacy models allow for greater operational flexibility of long duration storage and minimize
the need for daily charging and discharging. For the foregoing reasons, at minimum, pumped
storage should be treated like a traditional hydro facility with storage capability, which the Draft
IRP assigns a 60-100% peak capacity credit.6
b. Swan Lake and Goldendale Request Further Information on Avista’s Assumed
Useful Life for a Pumped Storage Project

Similarly, Swan Lake and Goldendale request that Avista provide further information on the
assumptions they used for the expected useful life of a pumped storage project. Swan Lake and
Goldendale’s experience—which is informed by discussions with pumped storage turbine
manufacturers and industry examples throughout the U.S. and abroad—suggests that a pumped
storage resource’s useful life is, at minimum, 40 years, and more likely will last 50 years or more.
Using an appropriate useful life will ensure pumped storage’s costs are properly considered over
the long time horizon in which a pumped storage resource will continue to reliably operate.
c. Swan Lake and Goldendale Request Further Information on Whether Avista’s
Pumped Storage Analysis Specifically Considered the Swan Lake Project

Given the statements in the Draft IRP noted above regarding a potential mismatch of timing, Swan
Lake and Goldendale request further information from Avista on whether it specifically considered
the Swan Lake project. While both Swan Lake and Goldendale are among the most mature and
viable pumped storage projects in the region, it appears Avista’s analysis assumes Swan Lake will
not be available to meet its small 2026 capacity need of 12 MW, nor would Swan Lake be available
to meet the much larger need of 301 MW in 2027.7 However, Swan Lake is expected to achieve
commercial operation in late-2026, so Swan Lake and Goldendale are concerned that Avista’s
6 Draft IRP at 9-28, Table 9.12. 7 See id. at 7-3.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 767 of 1105
analysis is not considering the Swan Lake project, despite it being a viable option that aligns with Avista’s capacity needs. Furthermore, Avista’s capacity figures assume Colstrip remains part of its portfolio through 2025; however, this assumption may not be prudent, considering the faster-than-expect push to retire coal plants throughout the region. In a scenario where Colstrip retires earlier than expected—which Swan Lake and Goldendale believe is more likely than not—Avista’s capacity need would significantly increase, thereby further supporting Avista’s early action on a potential capacity RFP, as further explained in Section IV below.
III. The Draft IRP Should Remove New Natural Gas as a Viable Resource Option In addition to the CETA requirements that mandate the removal of emitting generation sources from Avista’s generation portfolio, Governor Inslee also recently announced legislation that would phase out all natural gas in homes and businesses by 2050.8 Furthermore, Avista has a stated goal of having a carbon neutral electricity supply by 2027 and having 100 percent clean electricity by 2045.9 Given these recent developments, which highlight the unfriendly political environment for natural gas, instead of proposing to construct new natural gas facilities, Avista should focus its efforts on a Preferred Resource Strategy that aligns with both CETA and this evolving political landscape.
To the extent Avista believes new natural gas resources are allowable under CETA, Swan Lake
and Goldendale request that Avista provide a detailed explanation for why a new gas resource
would meet one of the few and limited CETA provisions allowing construction of such resources,
particularly including violation of reliability standards and, if violations are possible, whether
pumped storage could help alleviate or solve those potential violations. Furthermore, considering
the unfriendly political climate for new gas resources and Avista’s own commitments to
transitioning to a carbon-free future, Swan Lake and Goldendale request that Avista re-run its IRP
analysis with a constraint of no new natural gas resources. Doing so would likely result in pumped
storage being in the Preferred Resource Strategy, considering the statements noted above.

Swan Lake and Goldendale would also remind Avista and the Commission that, Avista need only
look to Portland General’s IRP process for evidence of the political realities associated with permitting new gas resources. Specifically, a few years ago, Portland General attempted to expand its Carty Generating Station (referred to as “Carty 2”). When Portland General proposed expanding the capacity of Carty in its IRP process, significant stakeholder opposition immediately arose and effectively killed the gas-fired plant as a potential solution to meet Portland General’s future capacity needs. Therefore, Avista should be aware that environmental groups, renewable resource developers, and many stakeholders will likely align to uniformly oppose any new gas facility. As a result, Avista should instead remove new gas as an option from its Draft IRP and re-
8 See Washington State Proposes Legislation to Phase Out Natural Gas Utility Service, S&P Global, Jan. 6, 2021, available at: https://www.spglobal.com/marketintelligence/en/news-insights/latest-news-headlines/washington-state-proposes-legislation-to-phase-out-natural-gas-utility-service-61819435. 9 Avista Declares Clean Electricity Goal, April 18, 2019, available at: https://www.myavista.com/-/media/myavista/content-documents/our-environment/cleanelectricitygoalnewsrelease-pdf.pdf.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 768 of 1105
run the analysis to determine a Preferred Resource Strategy that aligns with both CETA and Avista’s own climate goals.
IV. Swan Lake and Goldendale Strongly Support Avista Issuing a Capacity RFP As Soon As Possible In the Draft IRP, Avista indicates may release a capacity RFP as early as 2021. Specifically, the Draft IRP states, “To meet the January 1, 2026 capacity shortfall and to validate Avista’s preferred choice of long duration pumped hydro to meet this deficit, Avista may release a capacity RFP as early as 2021. . . Avista is still committed to releasing a capacity RFP subject to the needs of the final 2021 IRP.”10 Swan Lake and Goldendale strongly support Avista’s plan to release a capacity RFP as soon as possible. While Swan Lake and Goldendale have highlighted some of their concerns regarding the modeling and assumptions used for pumped storage in these comments, the only accurate way for Avista to fully evaluate potential pumped storage projects—including the various projects’ pricing information, timing for construction, and whether the operating characteristics align with Avista’s needs—is through actual proposals received through an RFP. Without an actual offer submitted through an RFP, Avista will be relying on its own assumptions and expectations regarding the price, timing, and operating characteristics of pumped storage. Furthermore, because pumped storage resources are relatively unfamiliar to many utilities in the Pacific Northwest, these
resources are at a disadvantage in the IRP modeling and evaluation process, particularly when
compared to other resources with which utilities are more familiar and have better data.

Therefore, Swan Lake and Goldendale overwhelmingly support Avista issuing a capacity RFP as
soon as possible to evaluate potential clean-capacity resources to meet its identified capacity needs.
Swan Lake and Goldendale request that Avista confirm its intention to do so and, if necessary, the
Commission and Commission Staff specifically direct Avista to prepare and issue such an RFP as
promptly as possible.
10 Draft IRP at 14-5.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 769 of 1105
V. Conclusion Swan Lake and Goldendale appreciate the opportunity to provide these comments on the Draft IRP. While Swan Lake and Goldendale are encouraged by some of the statements in the Draft IRP that suggest pumped storage is the preferred resource, Swan Lake and Goldendale believe further work needs to be done on the pumped storage modeling and analysis, as well as to remove natural gas as a viable option for fulfilling Avista’s future capacity needs. If you have any questions, please contact the undersigned.

Sincerely,

/s/ Nathan Sandvig
Nathan Sandvig [e-mail]
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 770 of 1105

February 5, 2021

Mark Johnson, Executive Director/Secretary
Washington Utilities and Transportation Commission
1300 S. Evergreen Park Dr. S.W., P.O. Box 47250
Olympia, Washington 98504-7250

Re: Avista 2021 Draft Integrated Resource Plans for Electricity and Natural Gas
Dockets UE-200301 (electricity) and UG-190724 (natural gas)

Mr. Johnson;

The NW Energy Coalition (“NWEC” or “Coalition”) appreciates the opportunity to comment on
the draft Integrated Resource Plan (“IRP”) submitted by Avista Utilties on January 4th, 2021, per
the Notice of Opportunity to File Written Comments issued by the Commission on January 5th,
2021.

The Coalition is an alliance of more than 100 organizations united around energy efficiency,
renewable energy, fish and wildlife preservation and restoration in the Columbia basin, low-
income and consumer protections, and informed public involvement in building a clean and
affordable energy future.

The Coalition notes Avista’s timely submission of a draft integrated resource plan (IRP) in
compliance with the schedule established by the Commission. We hope our comments will
be useful in revising the IRP for its final submission. The utilities must soon prepare their first
CEIPs under CETA. It is extremely important that the IRP/CEAP be technically correct and
thorough, since it “informs” the CEIP. The specific actions the utility plans to undertake as
described in the CEIP per 19.405.060(1)(b)(i) and (iii) are intended to be informed and
consistent with the IRP. Shortcomings in an IRP/CEAP must not be used as a means to limit the
utilities’ attainment of CETA standards in their CEIP. A CEIP based on an insufficient IRP/CEPA
analysis that fails to create a path towards meeting the 2030 standards will not be acceptable.

Our comments address both the overall context for planning and specifics issues in the IRP.

The standard for integrated resource planning has changed

Unlike previous planning cycles, CETA unequivocally established standards for 2030 and 2045.
The approach to integrated resource planning and resource acquisition planning should have
changed accordingly. IRPs are no longer simply analyzing lowest reasonable cost alternatives,
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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 771 of 1105

but lowest reasonable cost alternative pathways that lead to achieving the 2030 and 2045
standards. That is the analysis needed to provide the data and context for specific targets and
actions in the CEIP.

CETA’s intent is to transform the electric system - it requires a utility to: (1) eliminate coal fired
resources from a utility’s allocation of electricity by the end of 2025; (2) achieve cost-effective
conservation and efficiency to reduce load; (3) reduce demand as much as possible with
demand response actions; and (4) use electricity from renewables and non-emitting generation
1 to serve 80% of the remaining retail load by 2030, and 100% by 2045.
This first round of IRPs under CETA should be clearly focused on how to reach the goals, not
how to approximate the standards or to reach a utility’s own vision of “carbon neutrality”,
while ignoring the statutory requirements.
Avista’s explanation for the Clean Energy Targets table (CEAP p. 15-4, table 15-2) indicates that
may be the case in the CEAP. Avista raises the strawman that “use” of electricity from
renewable and non-emitting sources means “minute-by-minute tracking” of electrons. That is
not the case. While the rules regarding “use” are still being developed, the language of the
statute is clear. As Avista states in the introduction to the CEAP “this Action Plan is subject to
change prior to the April 1, 2021 IRP filing date to account for potential renewable resource
acquisitions from the 2020 Renewable FRP and as final CETA rules by the Washington Utility
and Transportation Commission (WUTC) are issued”. An IRP should analyze the various
pathways to meet the standards as set out in statute.

For example, using the data from that chart for a quick “back of the envelope” calculation, it
appears likely that Avista could meet the 2030 compliance standards for using electricity from
renewables and non-emitting to meet the 80% standard. Using the data in WA Clean Energy
Targets table 15.2, adjusting the net retail load of 641 aMW in 2030 to 80% amounts to 512.8
aMW. Most of that can be met with the 436 aMW from the renewable resources Avista
already owns. The shortfall of 76.8 aMW can be met with a little more than half of the planned
144 aMW from Montana wind. The 20% portion of retail sales, or 128.2 aMW, could be met
with various other resources listed on that chart.

Key Outcomes for the 2021 Avista IRP

The Avista 2021 IRP has two high priority tasks:
• First, to set a new direction in electric system planning in accordance with the policy
direction and compliance requirements of CETA. Both the policy and compliance
aspects are important.

• Second, to address system needs after the conclusion of 222 MW of coal plant service to
Avista customers by the end of 2025, as required by CETA, and other system changes,
especially the termination of the Lancaster 257 MW natural gas contract in 2026.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 772 of 1105

Recognizing that the draft IRP takes significant steps in the right direction, NWEC believes
additional improvements can be made for both tasks. We address these questions below in
two sections focusing on the overall IRP and the 2027 preferred resource portfolio.

While the draft IRP is not fully complete, Avista has presented a clear and detailed analysis,
provided work products and responded to stakeholder questions. The preferred portfolio
continues to develop energy efficiency and begins to lay out a strategy for acquiring demand
response resources, although we believe the targets can be increased and the pace can be
accelerated. The treatment of new renewable resources is somewhat more mixed, as
described below. Finally, significant improvement is needed for both the cost and capacity
value battery and pumped storage.

We also give special commendation to Avista’s Energy Equity analysis in chapter 13. This is a
strong first step in assessing energy burden and service quality across Avista’s Washington
service territory, especially for vulnerable populations and highly impacted communities.
Avista’s work is already setting a standard for utilities across the Northwest. We look forward
to further enhancements, including assessment of whether services and programs for customer
side resources like energy efficiency, demand response, distributed generation and electric
vehicle support are equitably available.

All that said, a significant question still should be addressed. While the draft IRP anticipates
retirement of Colstrip coal as early as 2021 and Lancaster gas in 2026, we are concerned about
the addition of 211 MW of new gas peaking capacity in 2027 to help address the gap. A new
peaker unit of that size would have a capital cost above $200 million, with additional fixed and
variable O&M including fuel cost, and would continue in operation for many years. We believe
further analysis will show that there are substantial available and cost-effective clean energy
resources that can defer or eliminate this new emitting resource.

Cross-Cutting Issues for CETA Policy and Compliance

A. Natural Gas Resource Risk

Even if the Avista gas fleet as a whole operates at a lower annual capacity factor over time,
continued additions of new gas capacity resources could pose both reliability and cost
concerns. Recent episodes including the BC pipeline explosion in October 2018, ongoing
restrictions in pipeline delivery and Jackson Prairie storage through the spring of 2019, and
more recently maintenance problems on the Williams pipeline through the Columbia Gorge in
the fall of 2020, highlight the tenuous situation for gas deliverability.

B. Market Reliance

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 773 of 1105

We commend Avista for a thorough market analysis (chapter 10) and provide the following
observations.

The price and availability risk in the short-term market (primarily the Mid-C trading hub) has
been growing in recent years. Underlying recent price disturbance episodes, including very high
prices in February-early March 2019 due to exceptionally cold weather and gas delivery
constraints, there is an underlying structural change in the Northwest bilateral market with two
key drivers.

First, a recent PacifiCorp presentation in an IRP workshop shows that the transaction volume
for the Mid-C trading hub has basically fallen in half over the last five years. There is some
evidence that much of the decline is the result of transactions moving to the Energy Imbalance
Market which is more liquid and has a favorable real-time pricing regime compared to the
outmoded high load hour/low load hour Mid-C construct. While EIM energy flows to load in an
economically beneficial manner, the EIM cannot assist with day-ahead and operational unit
commitment and dispatch.

Second, the retirement of Northwest coal resources and other changes is continuing to
diminish market supply relative to demand. This poses increasing price and availability risk
going forward.

Two other developments may counter the trend somewhat. For short term capacity, the
proposed Northwest Power Pool resource adequacy program could alleviate peak risk both
through advance commitments and an operational program. On the energy side, the Enhanced
Day Ahead Market expansion of the EIM could move forward, providing much deeper and more
liquid market access.

All that said, we conclude that the short-term market is increasingly risky, but we are also
confident that enhanced development of clean energy resources can help reduce market
exposure.

C. Social Cost of Greenhouse Gases (SCGHG)

The IRP analysis states “construction and operational greenhouse gas emissions are considered
and priced using the SCC”, but that the SCGHG was not applied to market purchases and sales
in the PRS as done previously. The reason for the change from previous practice is not clear.
The statute at 19.280.030(3)(a) states a utility must incorporate the SCGHG when evaluating
and selecting conservation policies, programs and targets; when developing integrated
resource plans and clean energy action plans; and when evaluating and selecting intermediate
term and long-term resources. The SCGHG is a variable cost used in planning to internalize the
costs of emitting CO2e. The SCGHG does not function as a tax that is passed through to
customers. In the modeling process, for both the IRP and CEAP, the SCGHG should be applied
to variable costs, dispatch modeling and unspecified or fossil fueled market purchases.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 774 of 1105

The impact of adding the SCGHG to market purchases is tested in portfolio #19 – SCC on
Purchases/Sales Resource Selection (IRP p. 12-29). This results in relatively little impact relative
to the PRS portfolio, except to select less solar. That result might well change if hybrid
resources, such as solar+battery were assessed, instead of charging storage with market
purchases.

Further, the Optimized SCGHG Carbon Future Portfolio shown in Table 12.24 not only improved
costs over the PRS, reduced natural gas by 88MW and increased energy efficiency and wind.
This option also reduced solar, but probably for the same storage charging reasons as in
portfolio #19.

In the final IRP/CEAP Avista should model a portfolio in which the SCGHG is optimized as a
variable cost and applied to unspecified and fossil fueled electricity brought in state for
customer use. This portfolio should also include hybrid resources, as discussed later.

D. Upstream Methane Emissions

An issue linked to the application of SCGHG is the life cycle emissions for gas power plants. As
we explained in a submission to the Northwest Power and Conservation Council,1 recent peer-
reviewed research has revised upstream methane emissions factors sharply upward. Because
of the current and proposed new addition of natural gas generation, we urge Avista to revisit
this issue and adjust the upstream methane emissions factor represented in the Social Cost of
Greenhouse Gas analysis.

2027 Preferred Resource Portfolio

With the cessation of coal power supply after 2025 and the expiration of the Lancaster gas
contract in 2026, the year 2027 is a useful point for evaluating system need and proposed new
resources.

In 2027, the draft IRP indicates a need for 301 MW of capacity. The draft proposes to fill the
gap with ongoing energy efficiency, the beginning of a demand response program, 200 MW of
Montana wind, a 12 MW upgrade at Kettle Falls, and 211 MW of peaker resources (85 MW for
Idaho and 126 MW for Washington/Idaho).

NWEC believes further review is needed on several categories of clean energy resources to see
if they can provide additional capacity value and defer or eliminate the need for new peaker
resources.

1 NWEC letter to Northwest Power and Conservation Council, June 15, 2020,
https://www.nwcouncil.org/sites/default/files/2020_0616_2.pdf
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 775 of 1105

A. Two Types of Capacity Need

The pivotal point to understand about the period after 2026 is that there are basically two
types of capacity need. We refer to these as typical and long-duration peak periods.

A typical peak period is that observed in most years, where demand peaks within a range
described by the median or “1-in-2” demand forecast.

Once or more per decade, a long-duration peak condition may occur, with extended high daily
peaks that may recur for two or more consecutive days, as reflected in a “1-in-10” forecast. In
the winter, these conditions may occur during very cold “Arctic express” periods where demand
is very high on a sustained level and renewable energy production is low. In such conditions,
the entire Northwest will be energy limited, market supply will be very expensive and perhaps
restricted, and gas supply from Canadian sources and storage withdrawals may also be
constrained.

In the late summer, similar heat wave conditions may occur. The reduced availability of hydro
peaking compared to winter stress conditions is an additional factor.

The question we pose is whether a staged approach to capacity need could provide a balanced
2027 resource portfolio that is better aligned with CETA policy guidance while meeting
reliability needs cost-effectively.

The first stage involves maximizing the availability of so-called “energy limited” clean flexible
resources, including demand response and storage. These are generally considered to provide
capacity value of 4 hours duration and should suffice for meeting needs during typical peak
periods.

In the second stage, meeting rare long-duration peaks requires supplemental resources. The
draft IRP suggests that new peakers can meet these supplemental needs. But once these very
expensive and high-emitting new peakers are put into the resource mix, the IRP models will
dispatch them not only for very infrequent long duration high peaks, but much more often
across the year because they are now “existing” resources. As a result, these new peakers will
displace less expensive, non-emitting resources. This creates a lost opportunity for CETA
compliant clean energy resources.

Avista should investigate the availability of firm capacity or other term resources to meet
infrequent long-duration event needs, for example from regional imports or merchant gas
plants. As time goes on, those resources could be replaced with new long-duration storage
from sources such as renewable hydrogen, renewable natural gas and pumped storage.

Below, we suggest the additional potential for clean flexible resources including demand
response, storage and hybrids to meet typical peaks.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 776 of 1105

B. Demand Response

The Conservation Potential Assessment (CPA) includes estimates for the technically available
potential of demand response, and the preferred portfolio includes initial steps toward
achieving that potential.

The CPA summarizes the technically achievable potential for DR at 90 MW in 2025 (about 5.1%
of peak load) and 170 MW in 2045 (almost 10% of peak). NWEC agrees that this is a reasonable
magnitude for total potential, but we believe it can be achieved considerably faster.

The preferred portfolio indicates 53 MW of DR in 2027 (3% of peak) in 2027. We believe
further assessment will show this amount can be increased.

For example, we estimate about 7 MW per year of technically achievable potential is available
from one specific resource – stock turnover and conversion to grid enabled residential electric
water heaters, or about 35 MW between now and 2027. In addition, new construction and gas-
to-electric conversions could increase the potential. This resource is facilitated by
Washington’s incoming requirement for all new electric water heaters to have a CTA-2045
communications interface, providing a common access standard.

It remains to be seen what level of customer participation can be achieved for a grid enabled
water heater program, but we anticipate that with effective customer engagement strategies it
can be higher than the 50% saturation assumed by Avista and the savings potential of 48.9 MW
by 2045 can be increased and significantly accelerated.

For demand response and load management as a whole, it is apparent that program launches
can be moved forward considerably. In the Clean Energy Action Plan, Table 15.1 indicates that
the first programs will appear in 2024, and the last in 2031. It would make more sense to
launch a coordinated set of DR programs earlier so they can scale up rapidly to meet capacity
need in 2027 and beyond. Portland General Electric has already succeeded in taking that path,
including both coordinated pilot programs and the Smart Grid Testbed. Their new Flexible Load
Plan lays out a strategy for moving DR to full maturity in the next 5 years.

C. Storage Cost
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 777 of 1105

NWEC believes that most of the reference resource costs in the draft RFP are in the reasonable
range, though we may have different views on specific resources and future cost trajectories.

However, the future costs for batteries and pumped storage simply don’t seem reasonable.
The values in Figure 9.1 show slight declines in battery costs, and then flat or rising costs
through the remainder of the planning horizon. Most other estimates show consistently
declining costs through the coming decades, though at varying rates.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 778 of 1105

Cost Projections for Utility-Scale Battery Storage, National Renewable Energy Laboratory
(2019). NREL/TP-6A20-73222, https://www.nrel.gov/docs/fy19osti/73222.pdf

Turning to pumped storage, the draft IRP states:

With the exit of Colstrip and the expiration of the Lancaster PPA in the fall of 2026, the
PRS adds 211 MW of natural gas-fired CTs. The 2020 IRP assumed the capacity lost from
Colstrip and Lancaster could be met with long duration pumped hydro, but the updated
cost and construction schedule information for pumped hydro caused this resource to
not be selected in this IRP. This modeling result is consistent with a scenario analysis
performed in the 2020 IRP showing natural gas CTs would be required if low cost long-
duration pumped hydro was not available by 2026. Avista will continue to follow
pumped hydro developments for future consideration.
Draft IRP at 11-5.

Table 9.6, Pumped Hydro Company-Owned Options, provides a summary of costs, but NWEC
does not fully understand the presentation and has not been able to pinpoint the underlying
data for this conclusion. There are at least two pumped hydro projects with a reasonable
chance of commercial operation by 2027, and further specific project assessment would be
useful.

D. Storage and Hybrid Capacity Value

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 779 of 1105

A notable aspect of the preferred portfolio is the lack of composite (hybrid) resources before
2038, when the first solar+battery resource appears.

The rapid emergence of hybrid resources around the nation and in the Northwest indicates the
importance of composite resources to meet both energy and capacity needs. A leading
example is PGE’s acquisition of a large portion of the NextEra Wheatridge project, an innovative
three-way hybrid of wind, solar and storage.

With regard to PacifiCorp’s current all-source RFP, it is widely expected that solar+battery
hybrids will be selected for half or more of the total acquisition, potentially amounting to more
than 2000 MW of solar capacity and over 1000 MW of battery storage.

A recent study by Astrape Consulting for Pacific Gas & Electric, Southern California Edison and
San Diego Gas & Electric found a substantial increase in ELCC value for Northwest (BPA
Balancing Area) wind hybrid resources. No value for solar hybrids was provided for the
Northwest because of insufficient data, but the effect is expected to be similar.

The values in the Astrape analysis are not directly comparable because they are with reference
to California ISO summer peak conditions. That said, the dramatic effect of battery availability
to shift energy to peak periods is clear. Yet the draft IRP indicates only a 17% peak credit value
for solar plus 4-hour battery resources and 15% for standalone 4-hour storage.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 780 of 1105

Whether the renewable resource is Montana wind with batteries or pumped storage shifting
energy into the morning and evening peaks, or eastern Washington solar plus batteries shifting
mid-day peak solar into late afternoon demand, NWEC views Table 9.12 as likely
underestimating peak value. In addition, there is no value listed for wind + storage (either
battery or pumped hydro), which is a clearly relevant use case.

As Avista proceeds towards the 2021 capacity RFP, we encourage revisiting this key issue.
Hybrid resources could provide a significant capacity benefit and defer the need for new gas
peakers, as well as make more effective use of limited available transmission capacity for
renewables and provide more operating flexibility.

Conclusion

The Coalition appreciates the work that has gone into the preparation of this draft IRP. We look
forward to collaborating on analyzing the changes we have suggested.

Respectfully,

Joni Bosh Fred Heutte
Senior Policy Associate Senior Policy Associate
NWEC NWEC
[e-mail] [e-mail]

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 781 of 1105
BEFORE THE WASHINGTON UTILITIES AND TRANSPORTATION COMMISSION
1 Electric Integrated Resource
Avista 1 Natural Gas Integrated
DOCKET UG-190724
COMMISSION STAFF COMMENTS REGARDING AVISTA CORPORATION d/b/a AVISTA UTILITIES
DRAFT INTEGRATED RESOURCE PLANS
SUBMITTED IN COMPLIANCE WITH
RCWs 19.405, 19.280 and WACs 480-90-238, 480-100-600 through -630
AND UNDER CONSOLIDATED DOCKETS UE-191023 AND UE-190698,
Order R-601

February 5, 2021
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 782 of 1105
Contents
Introduction ................................................................................................................................... 2 Summary of Staff Assessment.................................................................................................. 2
Gas Transportation Customer Conservation ......................................................................... 3
Recommendations related to the 2021 Final IRP................................................................... 4
Recommendations for the CEIP and future IRP planning cycles ........................................ 5
Staff Assessment of 2021 Draft Integrated Resource Plan by Focus Area ................................... 7
Clean Energy Action Plan ........................................................................................................ 7
Climate change ........................................................................................................................ 10
Load Forecasting ..................................................................................................................... 12
Upstream Emissions & SCGHG ............................................................................................ 13
Sub-hourly Modeling Capabilities......................................................................................... 14
Demand-Side Resources and Distributed Energy Assessments.......................................... 15
Distribution Planning and Non-Wires Alternatives ............................................................ 18
Nonenergy Impacts ................................................................................................................. 19
Customer Benefit Provisions in CETA ................................................................................. 20
Resource Adequacy Assessment and Uncertainty Analysis ................................................ 21
State Allocation of Resource Need ......................................................................................... 23
Electrification Scenarios ......................................................................................................... 23
Public Participation ................................................................................................................ 24
Data Disclosure........................................................................................................................ 25
Natural Gas Design Day (Planning Standard) ..................................................................... 26
Natural Gas CPA and Conservation Targets ....................................................................... 26
Renewable Natural Gas (RNG) ............................................................................................. 27
Appendices Appendix 1: Rules and statutes overview
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 783 of 1105
Introduction

On January 4, 2021, Avista Corporation d/b/a Avista Utilities (Avista or company) submitted its
draft Integrated Resource Plan (Draft IRP) in Dockets UE-200301 and UG-190724. The
Washington Utilities and Transportation Commission (UTC or commission) posted a Notice of
Opportunity to File Written Comments and Notice of Recessed Open Meeting. Written
comments are due by February 5, 2021, and the recessed open meeting is scheduled for 9:30 a.m. on Tuesday, February 23, 2021. The company will file its completed 2021 IRP (Final IRP) with the Commission by April 1, 2021.1 Commission staff (Staff) prepared these comments to assess whether Avista’s Draft IRP satisfies the rules and statutes governing the company’s IRP filings, highlight areas of strength in the Draft IRP, suggest opportunities for improvement in the final IRP, and make recommendations for the clean energy implementation plan and the next integrated resource planning cycle. In developing these comments, Staff consulted with Jeremy Twitchell from Pacific Northwest National Laboratory. Summary of Staff Assessment Electric: Avista’s public process, data transparency, and analysis of results were executed well.
While the company’s handling of equity and the customer benefit mandate is understandably underdeveloped, Staff is comfortable with the trajectory and looks forward to working closely with
the company. However, the company’s Draft IRP can be improved in terms of clarity and thoroughness in certain areas. Staff has concerns that the utility is undervaluing flexible resources
such as storage, solar, and distributed energy resources (DERs), because of incomplete analysis
of the impact of climate change, lack of sub-hourly modeling, the lack of a comprehensive DER
resource assessment, and limited application of nonenergy impacts.

Avista plans to meet or exceed the clean energy standard by acquiring 375 MW of clean energy
resources by 2031. As shown in Figure 1, the preferred portfolio (or preferred resource strategy
as labeled in the Draft IRP) has Avista economically exiting Colstrip in 2021 and over 300 MW
of natural gas plants by 2040. The preferred resource strategy includes the addition of new
natural gas peakers for system reliability in 2027 and 2036.

Natural gas: Overall, Staff is satisfied with Avista’s analysis and resulting preferred portfolio
for natural gas with the data available to-date and through Advisory Group participation. Without
inclusion of the appendices with the Draft IRP, there are details missing Staff has not been able
to fully analyze. Given that no new, large resource acquisitions are anticipated for natural gas
this document is heavily focused on the electric IRP. Recommendations for the IRP process for
natural gas often overlap with electric; Staff provides targeted comments on separate areas
specific to natural gas.

1 See Docket UE-180738, Order 02 (Nov. 7, 2019) and Docket UG-190724, Order 01 (Feb. 6, 2020).
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 784 of 1105

Figure 1: 2021 Preferred Resource Strategy2

Gas Transportation Customer Conservation
One tangential issue Staff brings to the Commission’s attention is the requirement in RCW
80.28.380 for the utilities to identify and acquire all conservation measures that are available and
cost-effective. While it has been the practice of the utilities to exclude gas transportation
customers from participating in their conservation programs, Staff struggles to find an exclusion
for gas transportation customers in the statutory language of RCW 80.28.380. Staff notes that the
IRP does not address the provision of gas for these customers; they acquire their own gas. Thus,
the CPA typically included in a gas IRP has not historically included any assessment of conservation for these customers. There is, however, a linkage between the conservation potential for these very large gas transportation customers and the expected distribution system improvements the company includes in the IRP. Acquiring that conservation should reduce the need for distribution system improvements.
2 Avista Draft 2021 Electric Integrated Resource Plan, Docket UE-200301, pp. 1-5, Table 1.1 , (Avista Draft Electric IRP) (Jan. 4, 2020).
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 785 of 1105
Staff expects the issue of conservation from gas transportation customers and its inclusion or exclusion from the target can be addressed on a case-by-case basis with each company during the approval of each company’s CPA and target. Recommendations related to the 2021 Final IRP
• Clean Energy Action Plan o Add a table to the CEAP that includes year-over-year capacity of all planned resources, including demand response.
o Include planned Appendix G with details of about planned transmission and
distribution improvements.
• Climate change
o Provide discussion regarding the implications of possibly moving from a winter
peaking utility to a dual or summer peaking utility.
• Load Forecasting
o Clarify the date in which its economic inputs were finalized. o Discuss any adjustments to the forecast made in response to the ongoing
pandemic. o Clarify the high and low load growth ranges used on page 3-14. For example, how did the company settle on the high and low assumptions for annual service area employment and population growth outlined in table 3.3? Please explain. o Discuss the assumptions behind the EV and solar PV forecasts that are inputs into the load forecast. o Clarify which of the two climate change forecasts the IRP uses.
• Upstream Emissions & SCGHG o Include in the narrative description required by WAC 480-100-620(11) a clear articulation of how the company calculated the SCGHG. o Discuss assumptions about the SCGHG in market purchases and charging storage resources with market purchases. o Explain why 1.0 percent is an appropriate upstream emissions factor for U.S. Rockies natural gas.
• Sub-hourly Modeling Capabilities
o Clarify storage cost assumptions.
• Customer Benefit Provisions in CETA
o Provide a scenario or, at minimum, a narrative regarding possible changes to
resource decisions that could increase customer benefit. o If available and time permits, incorporate the DOH data in the CIA.
• Resource Adequacy and Uncertainty o Clarify the company’s peak credit methodology, including the definition of “peak” terms. o Explain how the company incorporates uncertainty in the RA assessment.
• Public Participation
o Provide an IRP update based on any recent planned resource acquisition.
• Data Disclosure
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 786 of 1105
o Ensure appendices include a record of stakeholder feedback and the company’s response. o Provide context for the data files provided on the company’s website and submit in the docket.
• Natural Gas Design Day (Planning Standard) o Explain the new design day methodology. o Explain why the new design day standard is now the most appropriate one.
• Renewable Natural Gas
o Include details of RNG cost assumptions in the appendices.

Recommendations for the CEIP and future IRP planning cycles
• Climate change
o Incorporate a suite of variables, including snowpack, streamflow, and rainfall
parameters; meteorological trends; and load risks into the analysis. Staff believes
further study is needed.
o Consider additional resources, such as a climatologist or climate change
specialist, to analyze climate impacts over time on Avista’s system.
• Load Forecasting o Conduct a back cast of the load forecasting model, using actual values for their independent variable inputs to their load forecast to assess whether their models have systematic bias. o Include a section in the load forecasting chapter that “assess[es] the effect of distributed energy resources on the utility’s load,” as per WAC 480-100-620(3).
• Sub-hourly Modeling Capabilities
o Develop a workplan to expand sub-hourly modeling and discuss with
stakeholders.
o Expand sub-hourly modeling capability to appropriately evaluate DERs on equal
footing with utility-scale renewable and other supply-side resource options.
• Demand-Side Resources and Distributed Energy Assessment
o Treat DERs as generation resource in modeling, not just net from load.
o Optimize DERs with supply-side resources.
o Account for rate increases or pricing signals that can move peak demand and
change DER uptake.
o Consider issuing a RFI for DR without prescriptive screens to better understand
potential. o Take a proactive approach to DR program implementation in the CEIP,
accounting for longer lead time of customer sited programs. o Ensure programs in the CEIP are scalable.
• Distribution Planning and Non-Wires Alternatives o Start a public distribution planning process in 2022.
• Nonenergy Impacts
o Identify which nonenergy impacts are required and allowed for resource
selection.
o Include NEIs for all resources, as appropriate.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 787 of 1105
o Consider how NEIs do and do not overlap with equity requirements. o Identify where real data collection makes sense and where continued use of proxy is fine.
• Customer Benefit Provisions in CETA o Incorporate the Department of Health Cumulative Impact Assessment (CIA) into the IRP CIA. o Utilize the customer benefit indicators developed through the equity advisory group to design and model a maximum customer benefit scenario.
• Resource Adequacy and Uncertainty
o Incorporate the results of the regional resource adequacy program, as
appropriate.
o Discuss “peak” definitions within the advisory group.
• State Allocation of Resource Need
o Facilitate a discussion between Washington and Idaho stakeholders concerning
state allocation of resources.
• Electrification Scenarios o Consider effects of policy trends towards electrification on both the electric and natural gas systems.
• Public Participation o Provide additional time to review presentations prior to meetings. o Post meeting minutes in a timely manner and allow opportunity for revision. o Consider if additional staffing is required to adequately meet new IRP
requirements.
• Data Disclosure
o Provide contextual aids alongside data input files.
• Natural Gas Design Day (Planning Standard) o Explore the feasibility of using projected future weather conditions in its design
day methodology, rather than relying exclusively on historic data. The company
is conducting a similar analysis for a climate change scenario in its electric IRP.
• Natural Gas CPA and Conservation Targets
• Renewable Natural Gas
o Use any up-to-date cost and other data that is available to model potential RNG
resources.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 788 of 1105
Staff Assessment of 2021 Draft Integrated Resource Plan by Focus Area
Clean Energy Action Plan
To comply with statute and rules, Avista presented a ten-year clean energy action plan that works towards implementing the lowest reasonable cost solution, including incorporation of the social
cost of greenhouse gas emissions as a cost adder in its analysis.3 Specifically, each CEAP
should:
• meet clean energy transformation standards, including customer benefit provisions4;
• be informed by the utility’s ten-year cost-effective conservation potential assessment;
• identify the potential cost-effective demand response and load management programs
that may be acquired;
• establish a resource adequacy requirement and demonstrate how each resource,
including renewable, nonemitting, and DERs, may reasonably be expected to contribute
to meeting the utility’s resource adequacy requirement;
• identify any need to develop new, or to expand or upgrade existing, bulk transmission and distribution facilities; and
• identify the nature and extent to which the utility intends to rely on an alternative compliance option identified under RCW 19.405.040(1)(b), if appropriate.

Avista’s presents its draft CEAP as the lowest reasonable cost plan of acquisitions, given societal
cost, clean energy, and reliability requirements.5 Table 15.2 outlines Avista’s CEAP energy-
related projected new resources, identifying the year-over-year, resource ramp needed in the next
ten years to meet energy needs of both Idaho and Washington6 customers, including initial
“targets” to acquire an additional 375 MW by 2031 of new clean energy resources:

• 180 aMW of clean energy by 2031
o 144 aMW (300 MW) of Montana Wind
o 31 aMW from renewing a (75 MW) long-term hydro purchase power agreement
in 2031
o 5 aMW from a 12 MW upgrade to the Kettle Falls Generating Station (existing)
• Along with, under median hydro conditions, 41 aMW of clean energy purchases from Avista’s Idaho customers and 20 aMW of RECs.7
3 WAC 480-100-620(12).
4 WAC 480-100-610.
5 Avista’s plan exceeds goals of Washington’s Energy Independence Act (EIA), relying on the Palouse and
Rattlesnake Flat Wind contracts, generation from the Kettle Falls biomass facility and upgrades to the Clark Fork and Spokane River hydroelectric developments.
6 Avista notes its CEAP is specific to Washington’s portion of Avista’s system needs in compliance with CETA.
7 Avista notes, depending on the determination of the WUTC’s decision regarding compliance with the 100 percent
goal, Avista may need additional clean energy and/or RECs if renewable and non-emitting energy must be delivered to customers instantaneously. Chapter 12 of the 2021 Draft IRP outlines the cost and energy acquisition impacts of this scenario.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 789 of 1105
Avista is planning to procure resources capable of meeting Washington load. Questions remain regarding whether such resources could be dispatched in a manner to serve Washington demand: Does this clean energy resource acquisition imply clean energy operations? Operationally, how this energy is getting used and whether such “use” meets the spirit and letter of CETA remains a topic of discussion during Washington clean energy legislation implementation.8 In the Draft CEAP, Avista signaled preference for renewable projects located in vulnerable population areas to “further develop those economies,” indicating this does not include new generation facilities in Washington except for an upgrade to the Kettle Falls wood-fired facility, which Avista believes is not located in a vulnerable population area.9 Avista also provides a narrative and series of commitments related to the customer benefit provisions of CETA. The company plans to form an Equity Advisory Group (EAG) that is responsible to review the indicators and vulnerable populations, asserting the EAG will also help guide the design of the vulnerable population outreach and engagement and be used to distinguish and prioritize additional indicators and solutions needed to develop the upcoming Clean Energy Implementation Plan. Avista’s CEAP also includes a discussion of its analytical enhancements to include energy and non-energy benefits, and the company concludes these enhancements should benefit vulnerable communities. Staff agree that identifying non-energy
benefits is a good first step towards identifying customer benefit indicators and implementing
programs in a manner that ensures equitable distribution of energy and non-energy benefits.

Staff notes Avista’s projections outlined in this CEAP may change. Avista flagged in its Draft
IRP analysis that a future request for proposal (RFP) may identify a lower cost clean resource to
meet the first significant reliability shortfall and could yield resources more beneficial than those
more broadly identified in the CEAP.

For the draft CEAP, Staff is unable to provide an overarching recommendation due to the extent
of Avista’s draft submittal, including lack of complete appendices and modeling data for
examination. However, Staff offers several observations and suggestions for the Final IRP:

CEAP Presentation. The draft CEAP includes Table 15.1 with an outlay of DR programs, from
2024 through 2031, and a narrative, which identifies potential to reduce load by 37.6 MW by
2031, noting a 25 MW large commercial customer program offering may come to fruition before
the Lancaster PPA ends in 2026. Staff appreciates the company’s CEAP presentation in Table
15.2, representing the company’s year-over-year resource need in average capacity (aMW), or
the average power output of the facility over a given period, percent clean energy target and goal,
available resources, including owned and contracted, delineated by resource type and general
location (as appropriate), and projected shortfall.
8 See “Use” discussion docket notice relating to Clean Energy Implementation Plans and Compliance with the Clean Energy Transformation Act, Docket UE-191023 (June 12, 2020).
9 Avista Draft Electric IRP at 15-5. Note that Avista formats the pages of the IRP with dashes. To avoid confusion, throughout these comments Staff cites a single page as “XX-XX”, and multiple pages in the draft IRP with a “XX-XX to XX-XX” format.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 790 of 1105
For nameplate capacity presentation (MW), Avista provides Table 1.1 in the IRP, which provides the company’s “preferred resource strategy” through the 2045 but lists Demand Response at the bottom of the table with no timing specified, other than “2045 capability.”10 Staff points to the new IRP rules, which define CETA-related resource need as: any current or projected deficit to reliably meet electricity demands created by changes in demand, changes to system resources, or their operation to comply with state or federal requirements. Such demands or requirements may include, but are not limited to, capacity and associated energy, capacity needed to meet peak demand in any season, fossil-fuel generation retirements, equitable distribution of benefits or reduction of burdens, cost-effective conservation and efficiency resources, demand response, renewable and nonemitting resources.11 For the final CEAP, Staff suggest Avista also include incremental nameplate capacity (MW), or maximum capacity, including in tabular form year-over-year, showing the timing of all planned capacity resources: (1) existing and contracted resources (identified by resource type, location, or potential location); (2) peak import projections; (3) peak capacity needs before demand-side resources (developed from forecast + planning margin); (4) demand-side resources; and (5) peak
capacity resource need net demand-side resources.

CEAP resources. The evaluation of delivery systems, including transmission expansion is
becoming increasingly important because resources are becoming more geographically diverse
and shared among utilities.12 The definition of lowest reasonable cost in the IRP rules includes
planned resources and “related delivery system infrastructure,” which shows consistency with
chapters 19.280, 19.285, and 19.405 RCW. Staff notes Avista’s CEAP does not discuss
significant transmission or distribution improvements. Instead, the company briefly explains
these resources are “likely to be off system or utilize existing transmission assets, not requiring
new investment in the next ten years,” as shown in Appendix G.13 Staff looks forward to
reviewing Appendix G in the Final IRP, noting details were not provided for stakeholder review
as part of the Draft IRP.

Recommendations for the Final IRP:

• Add a table to the CEAP that includes year-over-year capacity of all planned
resources, including demand response.
10 Staff notes in Table 1, demand response and load management programs are essentially footnoted, not included in
the resource year-over-year ramp in the table or represented side-by-side with other resource type, contracts, or other
plant acquisitions.
11 WAC 480-100-605.
12 Juan Pablo Carvallo et al., Implications of a regional resource adequacy program on utility integrated resource
planning - Study for the Western United States, Energy Analysis and Environmental Impacts Division, Lawrence
Berkeley National Laboratory, p. 15, Table 3.5 (November 2020).
13 Avista Draft Electric IRP at 15-4.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 791 of 1105
• Include planned Appendix G with details about planned transmission and distribution improvements. Climate change Staff is concerned Avista’s modeling of climate change in this IRP is not comprehensive. Avista considered historical weather trends during load forecasting and ran a climate change scenario. Still, the possible risks of climate change on resource adequacy and optimal resource portfolio deserve a more complete and nuanced approach in the future.
Avista’s expected case load forecast incorporated historical trends that show HDD gradually
declining and CDD gradually increasing. The company contemplated using two different data
sets of trending HDD and CDD forecasts, one using Avista-specific data and the other using
Northwest Power and Conservation Council (NWPCC) state-level data. Both forecasts indicate
that Avista’s summer peak will grow faster than the winter peak, with the average summer peak
eventually higher than the average winter peak.14 However, the NWPCC trended forecast shows
the summer peak increasing faster, where the winter peak is growing slower than Avista’s
trended forecast.
Recent regional climate change analysis in the Northwest shows, “anticipated increases in temperature will alter the pattern of electricity use, where higher temperatures and more precipitation tend to result in more rain and less snow during the winter months, thus reducing the snow pack and subsequent summer flow.”15 Importantly, Avista’s forecast shows the high end summer peak (95 percent confidence level) is never higher than the high end winter peak, while the NWPCC forecast shows the high end summer peak is expected to be higher than the winter peak around 2040.16 This analysis demonstrates to Staff there is a strong potential that climate change will likely move Avista from a winter peaking utility to a dual or summer peaking utility in the near future. Avista is incrementally moving in the right direction in the 2021 IRP with respect to
incorporating the effects of temperature changes over time; but overall, Avista’s climate change
analysis as fairly minimal. The company modeled only one climate shift scenario that
deterministically examined impacts to hydro production and reduced gas plant maximum
capabilities expected to result from climate change. Avista used NWPCC data that estimated
additional hydro generation in the winter and less in the spring and summer. To simulate climate
change impacts to load, Avista, with assistance from the Pacific Northwest Utility Conference
Committee, used NWPCC data to create linear trends in load by month. This scenario results in
marginally lower wholesale electricity prices and slightly lower emissions due to increased hydro
production.

14 Avista Draft Electric IRP at 3-23, Table 3.7
15 Northwest Power and Conservation Council, “Update on Climate Scenario Selection for the 2021 Power Plan”. Available at https://www.nwcouncil.org/sites/default/files/2020_04_p2.pdf.
16 Avista Draft Electric IRP at 3-24 to 3-25, Figures 3.20 and 3.21.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 792 of 1105
Avista refers to the NWPCC assessment of climate change impacts in its preliminary resource adequacy assessment presented in December 2020. The company expresses concerns with the limited inputs used to derive the potential climate adjusted load and hydro conditions but does agree that there are great regional resource adequacy risks in this area.17 Staff agrees and encourages Avista to use more rigor in its analysis exploring the effects of climate change on their system. Further, to adequately account for the effect of climate change, Avista could consider acquiring additional expertise regarding temperature impacts over time on Avista’s system, especially considering the company’s hydro-reliance position, as shown in Figure 2. Staff suggests the company take a closer look at the methods peer utilities are taking. For example, Seattle City Light included a study on “Climate Change Effects on Supply and Demand,” as an appendix to its IRP, dedicating resources to assess the IRP climate sensitivity on the utility’s load-resource balance, including reduced snowpack, earlier melt, higher winter inflows, and lower summer inflows. This additional information provided insights into climate change scenarios’ effects to potentially change the expected base portfolio for supply and demand.18
Figure 2: 2020 Avista Capability and Energy Fuel Mix19

17 Avista Draft 2021 Electric IRP at 7-12.
18 NWPCC presentation on Climate Change and the 2021 Power Plan Workshop; Seattle City Light (May 1, 2019).
Also see Seattle City Light 2016 IRP, Appendix 12.
19 Avista Draft 2021 Electric IRP at 4-1, Figure 4.1.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 793 of 1105
Recommendation For Final IRP:
• Provide discussion regarding the implications of possibly moving from a winter peaking utility to a dual or summer peaking utility. For next IRP:
• Incorporate a suite of variables, including snowpack, streamflow, and rainfall
parameters; meteorological trends; and load risks into the analysis. Staff believes
further study is needed.
• Consider additional resources, such as a climatologist or climate change specialist,
to analyze climate impacts over time on Avista’s system.

Load Forecasting
In addition to the climate change-related recommendations above, Staff finds that the load
forecast section could use some clarification in the Final IRP. Avista conducted base, high-, and
low-load growth forecasts, as did its peer utilities. Comparisons to the other two utilities are difficult because the Draft IRP narrative lacks sufficient detail, including how Avista derived the input assumptions for the high- and low-load growth scenarios. One area where the Avista Draft IRP falls short of its peer utilities is discussing whether and how the ongoing COVID-19 pandemic has impacted its load forecast. For example, the company does not specify when its economic inputs into the forecast were finalized, or whether it has made any adjustments to the forecast to account for observed load impacts from the state’s stay-at-home orders. The state’s (and the nation’s) economy has been severely impacted since the pandemic’s onset in early 2020. For Staff to appropriately evaluate Avista’s forecast, especially considering the new 10-year Clean Energy Action Plan requirements which create mid-term requirements within the company’s 2045 planning horizon, more information is needed. Recommendation In the Final IRP:
• Clarify the date in which its economic inputs were finalized.
• Discuss any adjustments to the forecast made in response to the ongoing pandemic.
• Clarify the high and low load growth ranges used on page 3-14. For example, how did
the company settle on the high and low assumptions for annual service area employment
and population growth outlined in table 3.3? Please explain.
• Discuss the assumptions behind the EV and solar PV forecasts that are inputs into the load forecast.
• Clarify which of the two climate change forecasts the IRP uses.

In the next IRP:
• Conduct a back cast of its load forecasting model, using actual values for their
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 794 of 1105
independent variable inputs to their load forecast to assess whether their models have systematic bias.
• Include a section in its load forecasting chapter that “assess[es] the effect of distributed energy resources on the utility’s load,” as per WAC 480-100-620(3).
Upstream Emissions & SCGHG
For both the electric and natural gas IRP, Avista includes the social cost of greenhouse gases
(SCGHG) as a cost adder in its portfolio optimization of resource options, including upstream
emissions from natural gas. Avista describes the application of the SCGHG in several places in
the IRP. However, Staff finds the Draft IRP lacks a separate detailed methodology as to how the
company applies this cost adder in its electric portfolio optimization and preferred portfolio
selection. Staff expects Avista to provide a narrative illustrating step-by-step how the SCGHG
cost adder is applied throughout its modeling logic, including associated cost calculations, with
the Final IRP.20

For upstream methane emissions, Avista uses a global warming potential (GWP) factor that was
calculated based on the International Panel on Climate Change’s Assessment Report 5 (IPCC
AR5), which Staff prefers over older analyses. Avista uses the upstream methane leakage factor
of 0.77 percent for Canadian natural gas, and uses 1.0 percent for the U.S. Rockies natural gas
factor. Given that this U.S. Rockies natural gas emissions factor is significantly lower than any
of the factors analyzed by the NWPCC in its analysis of upstream natural gas emissions, Staff
recommends the Final IRP explain why the factor is appropriate.
In the expected case, Avista did not apply the SCGHG for market transactions but did include a
scenario to test the effect of applying SCGHG to the annual average emissions rates of net
market purchases. Including this value on market emissions led to additional procurement of
wind and less storage and solar. This is likely due to the assumption that the energy used to
charge storage resources comes from market purchases. Staff recommends additional narrative
describing how Avista selected these assumptions regarding market purchases.
During the advisory group process, the company was responsive to Staff’s request to use the annual incremental emissions rate instead of the annual average emissions rate when assuming a value for SCGHG reduction for energy efficiency. Avista performed a sensitivity to understand how this assumption changed the selection of energy efficiency. The company found that using the average rate savings are 12 percent lower by 2045 (10 aMW less) than when using the incremental rate.
Due to the uncertainty during rule development, Avista developed and performed three different
scenarios to help inform the cost of CETA mandates:

• Baseline 1 incorporates the SCGHG but does not include the clean energy standards,
• Baseline 2 achieves the clean energy standards in CETA without using the SCGHG,
• Baseline 3 excludes both the clean energy standards and the SCGHG.
20 WAC 480-100-620(11).
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 795 of 1105
By varying the baseline assumptions and modeling the SCGHG in several ways, Avista provided useful insights into the effect of legislation. However, the Draft IRP provided insufficient narrative describing how the company included SCGHG in the scenarios and the preferred portfolio. Staff recommends a separate narrative that focuses on the different methods Avista used to model the SCGHG in addition to the individual explanations throughout the document. Recommendation: In its Final IRP, Avista should:
• Include in the narrative description required by WAC 480-100-620(11) with a
clear articulation of how the company calculated the SCGHG.
• Discuss assumptions about the SCGHG in market purchases and charging
storage resources with market purchases.
• Explain why 1.0 percent is an appropriate upstream emissions factor for U.S.
Rockies natural gas.

Sub-hourly Modeling Capabilities To fully capture the value of flexible resources such as storage or demand response, IRP models need to have enough granularity to capture intra-hour variables. Modeling sub-hourly dispatch
can readily integrate resources offering more granular grid services into portfolio development.
For storage resources, it is unclear what is included in the company’s cost assumptions and Staff
expects these details to be included in the Final IRP.

Staff is concerned about Avista’s current ability to optimize all the resources needed for a
reliable one hundred percent clean system. With increasing renewable energy on the grid Avista
will be challenged to match generation and load. The current paradigm of planning to a peak in
winter when the wind isn’t blowing must be realigned to recognize that the utility must also plan
to a summer peak with an intra-hour weather anomaly. Staff looks forward to updates from
Avista regarding its sub-hourly modeling functionality in its ADSS software for the next IRP.21

Avista must expand its sub-hourly modeling capability to appropriately evaluate DERs on equal
footing with utility-scale renewable and more traditional fossil resource options. Avista could
also transition to a LTCE optimization platform that endogenously considers the sub-hourly
benefits of DERs. Alternatively, the company can apply cost credits to better characterize the
sub-hourly grid services DERs provide, which in turn may increase the likelihood Avista’s
preferred resource portfolio solution would include these resource options. As discussed within
the Demand-Side Resources and Distributed Energy Assessments section of these Staff
comments, Avista should not assume future IRPs that handle distributed generation simply as a
load forecast decrement will be CETA compliant.
21 Avista Draft Electric IRP at 14-6.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 796 of 1105
Recommendation In the Final IRP:
• Clarify storage cost assumptions. Prior to the next IRP:
• Develop a workplan to expand sub-hourly modeling and discuss with
stakeholders.
• Expand sub-hourly modeling capability to appropriately evaluate DERs on equal
footing with utility-scale renewable and other supply-side resource options.

Demand-Side Resources and Distributed Energy Assessments
Energy efficiency, demand response (DR), and other distributed energy resources (DERs) are
essential to a clean energy system that adequately serves and benefits all customers. Avista has
made a reasonable attempt to value acquisition of energy efficiency and demand response in the
Draft IRP but has not sufficiently analyzed other DERs. Avista, like PSE and Pacificorp,
performed potential assessments for EE and DR but only used a forecast of EV and PV adoption. The modeling of DER is a major weakness in the Draft IRP. Electric vehicle charging and net-metered generation are accounted for in the load forecast, but DERs, except for EE and DR, are not otherwise valued as potential resources. Avista signaled plans to further integrate DERs in the 2025 IRP.22 This is discussed further in the Distribution Planning and Non-Wires Alternatives section below. Energy efficiency CETA has not made any notable changes to the methods used to model energy efficiency (EE). Avista once again retained AEG to perform the conservation potential assessment (CPA) for both the electric and gas IRP. The draft IRP and associated data provide sufficient information to calculate the ten-year, four-year, and two-year cost-effective conservation potential under both CETA and the EIA. The pro-rata share of the ten-year potential is 101,566 MWh.23 Avista used an iterative process to identify the cost-effective EE to be removed from the load forecast. Figure 3 below shows the avoided cost of EE for energy and capacity with components broken out. Over the planning horizon the levelized price of EE is projected to be 3.5 cents per kWh.
22 Avista Draft Electric IRP at 2-11 and 14-8.
23 Id. at 5-8.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 797 of 1105

Figure 3: Washington Energy Efficiency Avoided Cost24

Demand response
To identify all cost-effective demand response as required by CETA, Avista hired AEG to
perform a demand response potential assessment (DRPA) like the CPA for conservation and
similar to the DRPA performed in the last IRP. 25 The DRPA includes sixteen residential and
commercial programs, and Avista added Large Industrial Curtailment potential outside of the
DRPA.26 The programs include both controllable DR and rate design programs. Where
automated metering infrastructure (AMI) is an enabling technology, Avista assumes AMI
deployment will be complete in Washington in 2022 (in Idaho the company assumes full
deployment in 2024).

DR is treated consistently among the Washington IOUs, including peak reduction as the primary
use case of demand response. The amount of reliable capacity contribution from DR should vary
by program type, number of events, and by length of event. PSE and Avista each appropriately
evaluated sixteen potential demand response programs, including direct load control and pricing
options. However, the utilities did not vary assumptions around the number and length of events,
potentially underestimating the potential that a different program design might provide a better
fit with the utility system needs. The amount of peak capacity credit given to DR for Avista was
60 percent of a gas-fired combustion turbine.

24 Avista Draft Electric IRP at 5-14, Figure 5.7.
25 WAC 480-100-610(4)(a)
26 Potential assessments assume average market penetration and savings over sizeable populations. Large industrial potentials in Avista’s service territory are more appropriately treated individually than on an average basis.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 798 of 1105
In line with the NWPCC methodology for 2021, the utilities assumed that energy efficiency takes place prior to demand response. In general, Staff agrees with this assumption. However, the specifics of each company’s approach lacked the nuance needed to appropriately capture the potential for EE and DR programs to enhance or interfere with each other. Staff acknowledges that this is a complicated task but anticipates efforts to model the interaction effects will be enhanced by utility efforts to integrate EE and DR program efforts during implementation. In recent years, utility modelling of demand response potential has received negative critiques from stakeholders. With the new mandate to pursue all cost-effective demand response, Staff expected the utilities to refine the modeling of this resource. Unfortunately, this round of IRPs has not made notable improvements over the last round. While Avista and AEG provided ample opportunity for public involvement around the achievable potential for DR, costs for DR were not made available during these meetings, thus not vetted by the advisory group. Staff has significant concerns regarding the treatment of grid enabled water heaters. Washington has established that electric storage water heaters sold in the state that are manufactured after January 1, 2021, must include a demand response communications port.27 Turnover of the state’s electric water heater stock will take some time but will steadily increase the potential of this resource without additional equipment being required at customer premises. This technology
allows frequent load curtailment requests by the utility while ensuring a large supply of hot water
remains available to the customer.28 While each utility included this technology in the potential
assessments, no utility provided sufficient discussion of potential program costs and assumptions
with the advisory group. Staff requests Avista give this technology additional consideration.
Given the large size of a potential program and the current inexperience of northwest utilities
with demand response, it is likely costs are overestimated and reliability is underestimated.

Recommendation

In the Final IRP:
• Provide the conservation potential assessment model and underlying data.
• Provide the demand response potential model and underlying data. In the next IRP:
• Treat DERs as generation resource in modeling, not just net from load.
• Optimize DERs with supply-side resources.
• Account for rate increases or pricing signals that can move peak demand and change
DER uptake.
• Consider issuing a RFI for DR without prescriptive screens to better understand
potential.

In the CEIP:
27 RCW 19.260.080
28 See Bonneville Power Administration, CTA-2045 Water Heater Demonstration Report, (Nov. 9, 2018).
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 799 of 1105
• Take a proactive approach to DR program implementation, accounting for longer lead time of customer-sited programs.
• Ensure programs are scalable.

Distribution Planning and Non-Wires Alternatives
The IRP rules require the utility to include assessments of a variety of distributed energy
resources and the effect of distributed energy resources on the utility's load and operations.29
Further, the commission strongly encourages utilities to engage in a distributed energy resource
planning process as described in RCW 19.280.100. If the utility elects to use a distributed energy
resource planning process, the IRP should include a summary of these results.

In the Draft IRP, Avista provides a narrative of its distribution planning efforts, explaining how
the company continually evaluates its distribution system for reliability and level of service
requirements, including voltage and power quality, for current and future loads. However, Avista
did not identify any projects meeting the criteria for an economic non-wire alternative in the
Draft IRP. The company contends its near-term distribution projects require capacity increases
and duration requirements due to load growth exceeding the distributed energy resources (DERs)
capability.30

Although distribution systems will vary from one utility to another based on the unique
characteristics of each system, Staff points to Puget Sound Energy’s Draft IRP, which
illuminates the capacity value of such resource additions and illustrates the nexus between
distribution system and integrated resource planning. For example, PSE includes a line item of
distribution system planning incremental nameplate capacity for non-wires alternatives,
beginning in 2022 and growing to 118 MW total in the outer years of the plan.31 Staff supports
Avista’s continued efforts to continue to study new technologies and grow its situational
awareness of other utilities’ actions in this space.32

Staff suggests Avista continue to engage Staff and keep stakeholders updated on their commitment in the Draft IRP to start a public distribution planning process in 2022 to identify and plan for future distribution needs. This will allow the company to better anticipate future impacts under CETA and:
• analyze interdependencies among customer-sited energy and capacity resources;
• reduce, defer, or eliminate unnecessary and costly transmission and distribution capital
expenditures;
• identify and quantify customer values that are not represented in volumetric electricity
rates and maximize system benefits for all retail electric customers; and
29 WAC 480-100-620(3) Distributed energy resources.
30 Avista Draft Electric IRP at 8-9.
31 Puget Sound Energy Draft 2021 IRP, Docket UE-200304, pp. 1-4, Figure 1-4 (“DSP Non-Wire Alternatives”).
32 Avista describes its distribution system as consisting of approximately 350 feeders covering 30,000 square miles, ranging in length from three to 73 miles.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 800 of 1105
• identify opportunities for improving access to transformative technologies for low-income and other underrepresented customer populations.33 Recommendation In 2022:
• Start a public distribution planning process.

Nonenergy Impacts
As described in the appendix to this document, CETA has emphasized the consideration of
nonenergy costs and benefits of resources in system planning. In the past, Staff has pushed
utilities to account for nonenergy impacts (NEIs) such as the expected emissions of greenhouse
gases and particulate matter with quantified health risks.34 Avista’s treatment of nonenergy costs
and benefits in this IRP has gone further than any past effort, in large part because of the
requirement to include the social cost of carbon.

To address other NEIs connected to public interest objectives such as public health, energy
security, environmental benefits, costs, and risks, all three electric IOUs relied on a proxy
method using data from the Environmental Protection Agency (EPA).35 The EPA data includes
NEI values generally applicable to all energy efficiency and renewable energy in the Pacific
Northwest. Avista analyzed this data to align with its service territory, landing on a benefit value
of $8.90 per MWh. The company then applied this benefit uniformly to energy efficiency
measures to approximate unquantified NEIs.

While all utilities started with the EPA data, Avista’s proxy benefit value is approximately one
half what PSE used and one third of what Pacific Power plans to use in the 2021 IRPs.36 Staff
acknowledges that none of these proxy values accurately capture the value of NEIs, but we
appreciate each utility acknowledging that the nonenergy benefits of EE are, on the whole, greater than zero. Prior to the next IRP, Staff expects significant work with utilities and stakeholders to identify which NEIs should be valued, what values can be adequately quantified, and when the use of proxy values is most appropriate. The primary limitation to the approach Avista took to account for NEIs in the IRP is only applying NEIs (outside of the SCGHG) to energy efficiency. NEIs exist for all resources but most have traditionally only been included when evaluating demand-side resources, as the proximity of these resources to customers naturally increases impacts.
33 RCW 19.280.100.
34 Staff Comments on 2018-2019 Biennial Conservation Plans, Dockets UE-171087, UE-171091, and UE-171092, p. 8-9 (Dec. 1, 2017)
35 Environmental Protection Agency, Public Health Benefits per kWh of Energy Efficiency and Renewable Energy in
the United States: A Technical Report, (July 2019).
36 PSE used a proxy value of $0.02 per kWh ($20.00 per MWh), Pacific Power used $28.70 per MWh, Avista used $8.90 per MWh.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 801 of 1105
Recommendation In the next IRP:
• Identify which nonenergy impacts are required and allowed for resource selection.
• Include NEIs for all resources, as appropriate.
• Consider how NEIs do and do not overlap with equity requirements.
• Identify where real data collection makes sense and where continued use of
proxy is fine.

Customer Benefit Provisions in CETA
In the Draft IRP, Avista did not perform a maximum customer benefit scenario or sensitivity as required by the new rule.37 Staff understands that this work dramatically departs from the traditional planning done in the IRP and including it in the Draft IRP may not have been feasible. Staff encourages Avista to make best efforts to model a scenario that would maximize customer benefits in the Final IRP. Given that the maximum customer benefit scenario is a new requirement that will be improved upon and clarified over time, Staff requests the company develop a narrative describing Avista’s current interpretation of the rule and proposed next steps regarding intent to model the scenario. Avista completed commendable work by developing a preliminary methodology for geographically identifying highly impacted communities and vulnerable populations. Avista identified two census tracts as qualifying highly impacted communities. To identify vulnerable populations, the company used the Environmental Health Disparities Map maintained by the Department of Health (DOH) to score areas based on pollution burdens and population characteristics. The company acknowledges that this is an ongoing process that is currently missing several important inputs. For the Draft IRP, no utility was able to incorporate the Cumulative Impact Assessment (CIA) prepared by DOH, which was expected by the end of 2020.38 DOH’s work on this has been delayed and may not be available for inclusion in the Final IRP. The baseline analysis Avista
performed in this IRP identified where there are significant differences in energy use, energy
cost, reliability, resiliency, and higher densities of power plant emissions. Avista will need to
change its methods to incorporate the DOH data into the next IRP, but Staff is satisfied with the
progress to date.

Plans for an equity advisory group (EAG) are well underway at Avista.39 The company is
conducting outreach and carefully considering how to successfully engage marginalized and hard
to reach populations. The EAG is separate from the IRP advisory group and will identify
37 WAC 480-100-620(10)(c).
38 RCW 19.405.140.
39 WAC 480-100-655(2).
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 802 of 1105
vulnerable populations and develop customer benefit indicators that will be incorporated into the CEIP planning and the next IRP. Staff look forward to Avista growing its current robust low-income programs to serve other highly impacted communities and vulnerable populations. Recommendation In the Final IRP:
• Provide a maximum customer benefit scenario and a narrative regarding Avista’s current interpretation of the rule and next steps for improvement.
• If available and time permits, incorporate the DOH data in the CIA.
Before the next IRP:
• Create the Equity Advisory Group by May 1, 2021, to provide useful and timely
input for the planning cycle. Staff understands that Avista has already begun
organizing this group and commends the company approach.
• Incorporate the DOH CIA into the IRP CIA.
• Utilize the customer benefit indicators developed through the equity advisory group to design and model a maximum customer benefit scenario. Resource Adequacy Assessment and Uncertainty Analysis As required by CETA, Avista must determine “resource adequacy metrics for the resource plan,” and identify “an appropriate resource adequacy requirement and measurement metric consistent
with prudent utility practice.”40 The IRP uses Avista’s Reliability Assessment Model (ARAM) to
test the current resource portfolio’s reliability metrics and the contribution of each resource.
Continuing from previous IRPs, Avista retains a 5 percent LOLP metric to ensure future system
reliability.

In Table 11.5, Avista also shows resource adequacy analysis related to three other reliability
metrics, including Loss of Load Hours (LOLH), Loss of Load Expectation (LOLE), and
Expected Unserved Energy (EUE). The company currently targets a 16 percent planning margin
to meet winter peaks, and 7 percent for summer peaks. This is in addition to meeting operating
reserves and regulation requirements.

Avista begins its resource adequacy analysis narrative with a discussion of regional coordination,
signaling that it is participating in the development of a potential regional resource adequacy
program. The company estimates participation in a resource adequacy program will reduce its
needs for new capacity by up to 70 MW in 2031 based on the current draft program design,
where these savings will potentially allow the utility to require lower future resource acquisition
if the program is developed and implemented.

Avista’s draft IRP analysis shows a capacity need of 83 MW of natural gas-fired capacity for
Washington customers by 2026, replacing the Lancaster Power Purchase Agreement (PPA), to
maintain reliability targets for Washington customers during peak load hours. The company
40 RCW 19.280.030(1)(g) and (i).
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 803 of 1105
assumes 330 MW of market availability for the 2021 IRP, compared to 250 MW in the 2017/2020 IRPs. Avista also indicates that a future RFP may identify a lower cost clean resource to meet this reliability shortfall, but the current IRP modeling results selected a gas-fired resource in 2026. The analysis of the contribution to RA by storage, DR, and variable energy resources is of particular interest to Staff in the first post-CETA IRP review. For the Final IRP, and into next IRP cycle, Staff suggest Avista include more information about how the company treats, or plans to treat, uncertainty in RA modeling within the IRP, including the following elements of its RA assessment: Resource ELCC Analysis For its (effective load carrying capability) ELCC analysis, Avista assigned peak credits to renewable and storage resources depending on resource ability to meet peak loads using its ARAM model. The company’s ELCC calculations should be a measurement of that resource’s ability to produce energy when the company is most likely to experience electricity shortfall, showing how that resource uniquely contributes to reliability requirements. Avista appears to translate its “peak savings” for demand response into a peak credit that differs
depending on duration. Specifically, Staff requests more description about how Avista derived
the Peak Credit shown in Table 9.12. For energy storage, when an 8-hour resource only gets a 30
percent credit and a 70-hour resource only gets to 90 percent, Staff questions how the utility
uniquely defines peak and peak-related demand terms.41 Staff requests additional narrative
related to the company’s methodology related to Peak Credit, including how Avista specifically
defines the terms “peak” and “peak-related” in the Final IRP.

Incorporation of uncertainty into RA assessment
Avista indicates “resource analysis identifies a natural gas CT to replace resource deficits if
pumped hydro is not a feasible resource to meet the 2026 shortfall. Avista will conduct
transmission and air permitting studies to prepare for this contingency. Avista expects this
process to take at least two years.”42 Relatedly, in the Draft IRP narrative for resource adequacy,
risk, and uncertainty analyses, it is not clear how the company accounts for renewable
contribution, storage efficiency, or construction.43 For example, construction risks could include
delays for new assets, other future considerations for resource maintenance, plant upgrades, or
transmission expansion uncertainties. Staff request additional narrative how the company
incorporates uncertainty in the RA assessment in the Draft IRP, or if the company plans to
address these elements in the next IRP cycle.
41 See Natalie Mims Frick et al., Peak Demand Impacts From Electricity Efficiency Programs Report, Energy Analysis and Environmental Impacts Division, Lawrence Berkeley National Laboratory, Appendix B, Table B-2 (Nov. 2019).
42 Avista Draft Electric IRP at 14-5.
43 See Juan Pablo Carvallo et al., Implications of a regional resource adequacy program on utility integrated resource planning - Study for the Western United States, Energy Analysis and Environmental Impacts Division, Lawrence Berkeley National Laboratory, p.17, Table 3.5 (Nov. 2020).
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 804 of 1105
Recommendation In the Final IRP:
• Clarify the company’s peak credit methodology, including the definition of “peak” terms.
• Explain how the company incorporates uncertainty in the RA assessment in the
Draft IRP, or if the company plans to address these elements in the next IRP
cycle.
In the next IRP:
• Incorporate the results of the regional resource adequacy program, as
appropriate.
• Discuss “peak” definitions within the advisory group.

State Allocation of Resource Need Historically, Avista’s allocation of planned electric system resources between states has been determined using the Production-Transportation ratio, which is approximately 65 percent Washington and 35 percent Idaho. As the two states’ policy objectives diverge, capacity and energy needs result from different drivers. In the Draft IRP, Avista has done an admirable job attempting to assign resource needs between one hundred percent Washington, one hundred percent Idaho, and a combined system need. Soon, both state commissions will need to grapple with complicated cost recovery allocation. Avista faces difficult questions related to future rate recovery resulting from long-term resource planning in two states for one utility system: Idaho customers will not want to pay increased rates that may result from CETA and Washington customers will not want to pay for potentially stranded assets from new gas resources. Staff encourages the company to bring stakeholders together for an in-depth discussion and analysis prior to any formal filing. Ultimately interstate cost allocation must be adjudicated, but Staff believes a collaborative process is worth pursuing. Recommendation Before the next IRP:
• Facilitate a discussion between Washington and Idaho stakeholders concerning
state allocation of resources.

Electrification Scenarios
In the electric IRP Avista performed three separate scenarios considering the effects that
electrification of space and water heat in Washington could have on the portfolio. Avista states
that the IRP is not the best vehicle to conduct these studies and recommends a separate regional
study. While Staff does not disagree about the usefulness of a regional or statewide study, the
company should continue to consider local policy trends towards electrification in both the
electric and natural gas IRPs.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 805 of 1105
Recommendation In future IRPs:
• Consider effects of policy trends towards electrification on both the electric and natural gas systems. Public Participation Avista demonstrated a robust public participation process during this IRP. They began by
seeking input on a draft work plan and once filed, stayed true to the plan. Avista originally
scheduled five technical advisory group meetings. When the scheduled meetings could not cover
all the material with the depth the company and advisory group members wanted, Avista added
additional webinars and a workshop. Avista provided Staff and the advisory group meaningful
opportunities to discuss complex resource planning processes, data assumptions, and other
interest topics throughout the IRP planning process. Avista’s IRP advisory group is open to all
members of the public who wish to participate.

Avista’s IRP Team is exceptionally responsive to members of the advisory group, taking input
under consideration and taking time to explain complex issues to ensure members were
comfortable with their understanding. Deadlines on comments and requests were clear but not
rigid. Further, the company provided draft presentations before meetings and followed-up with a
final version that contained any last-minute changes or corrections.

Staff recommends more time to review presentations before IRP advisory group meetings, which
is crucial for utilities to receive meaningful feedback during the meetings, especially considering
Avista’s IRP meetings now cover both gas and electric IRP topics. The company should provide
advisory group members meeting minutes and follow-up documentation promptly, allowing
members an opportunity to suggest revisions or clarifications as necessary. In the future, the
company may need to expand its core IRP team to include additional administrative support,
especially considering the new customer benefit provisions.

The company filed its Draft IRP on January 4, 2021, mostly complete, except for appendices.
Staff notes the lack of appendices is mostly balanced by the excellent data access and availability
of Avista staff to stakeholders. Staff also highlights the company’s outstanding approach to
transparent data access in the Data Disclosure section of this document.

In 2020, Avista put out a request for proposals (RFP) for renewable resources. The RFP process is in its final stages, and there is a possibility that the company will finalize the acquisition of a resource before filing the Final IRP. To the degree possible, Avista should update the Final IRP with any known resource. If an acquisition occurs soon after the Final IRP is filed, Staff recommends the company file, at minimum, an update to the preferred resource strategy and clean energy action plan so it can develop its CEIP based on the best available information. Overall, Avista’s public participation process is comprehensive and facilitates trust and transparency in the IRP development process. Staff provides recommendations to improve its
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 806 of 1105
public participation process for the next IRP cycle, particularly related to the new documentation and administrative requirements outlined in the rule.44 Recommendation In the Final IRP:
• Provide an update based on any recently completed resource acquisition. In the next IRP:
• Provide additional time to review presentations prior to meetings.
• Post meeting minutes in a timely manner and allow opportunity for revision.
• Consider if additional staffing is required to adequately meet new IRP
requirements.
Data Disclosure Avista appears to have best satisfied the data disclosure objectives Staff have highlighted for this first CETA-compliant 2021 IRP cycle of the three Washington electric investor-owned utilities. Overall, the company seems to have provided the data stakeholders requested during the 2021 planning process on time. Staff notes the record of stakeholder comments and company responses is one of the appendices not included in the draft.45 Unlike peer utilities, Avista’s IRP website does not contain an ongoing record of stakeholder comments, data requests, and questions received and addressed by the company.46 Staff understands that Avista plans to provide this information in the Final IRP but suggests a contemporaneous documentation strategy.47 Avista made many data input files available in native format to facilitate stakeholder review of data underlying the company’s planning decisions. Staff applauds Avista’s commitment to make data and models accessible to stakeholders by posting them to the company’s website and providing a webinar dedicated to understanding the PRiSM long-term capacity expansion model. To further increase accessibility and transparency, the company should provide contextual aids and organize its Final IRP deliverable by including a master table of contents, readme files, and categorically grouping related data.

Recommendation

In the Final IRP:
• Ensure appendices include a record of stakeholder feedback and the company’s
44 WAC 480-100-620, -625, and -630.
45 Appendix C of Avista’s Draft Electric IRP serves as the placeholder for public participation comments. However, the company has not filed any appendices with its draft deliverable.
46 PacifiCorp’s 2021 IRP stakeholder feedback website posts stakeholder feedback forms and company responses to
said forms, when available. Avista’s IRP website does not appear to include similar postings.
47 WAC 480-100-620(17).
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 807 of 1105
response.
• Provide context for the data files provided on the company’s website and submit data files in the docket. In the next IRP:
• Provide contextual aids alongside data input files.

Natural Gas Design Day (Planning Standard)
Avista’s peak day planning standard for natural gas is new to this IRP. In previous plans, the
company had used a coldest-on-record standard and has changed to a 99 percent probability of
experiencing an extremely cold temperature in each of its service areas. The data underlying
Avista’s new design day calculation indicates a warming trend in parts of its service territory, but
it is still based on historic data, not projections of future temperatures.

Staff requests Avista include a future climate change sensitivity similar to that provided by PSE
in its next natural gas IRP and provide more explanation around the new design day
methodology, including why this new standard is the appropriate choice. Staff believes a few
extra sentences explaining how it combines temperatures “with a 99% probability of a weather
occurrence” would make the methodology clearer. In its explanation, Avista should provide
additional narrative around Table 2.4 and Figures 2.4 through 2.8 to further describe the trends
they depict. On the surface, it seems counterintuitive, for instance, that the new design day
methodology has Medford’s planning standard significantly warmer than the previous
methodology did, while Klamath Falls’ peak day has gotten slightly colder, even though the two
cities are not that far apart.
Recommendation
In the Final IRP:
• Explain the new design day methodology, providing a more detailed narrative.
• Further explain why the new design day standard is now the most appropriate one.
In future IRPs:
• Explore the feasibility of using projected future weather conditions in its design day
methodology, rather than relying exclusively on historic data. The company is
conducting a similar analysis for a climate change scenario in its electric IRP.

Natural Gas CPA and Conservation Targets
Avista once again retained AEG to perform the potential assessment for both the electric and gas
IRP in Washington and Idaho. (Avista uses the Energy Trust of Oregon to conduct its Oregon
CPA.) The continuity in CPA contractors allowed Avista to make very few minor changes to the
CPA methodology. AEG estimated that Avista’s achievable economic conservation potential for
its Washington territory is 3.6 million dekatherms by 2040.

Staff has no suggested changes concerning natural gas CPA and conservation targets at this time.
It is important to note that Staff will be further analyzing the details of the CPA, including
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 808 of 1105
avoided costs, as part of the CPA approval process described in Appendix 1 to these comments. Renewable Natural Gas (RNG) The Draft IRP discusses RNG at length, including state and regional policy considerations, internal steps the company has been taking to prepare for an RNG program, gas quality specifications, and options to build or buy projects. Avista acknowledges that its cost-effectiveness evaluation methodology for RNG is a work in progress. A voluntary RNG program is currently in development. Staff look forward to reviewing detailed assumptions of RNG in the Final IRP. Recommendation: In the Final IRP:
• Include details of RNG cost assumptions in the appendices.
In future IRPs:
• Use any up-to-date cost data that is available to model potential RNG resources.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Appendix 1

Introduction

The passage of the Clean Energy Transformation Act (CETA, E2SSB 5116) in 2019 introduced
many critical changes to the ways in which electric utilities conduct their integrated resource
planning (IRP) processes. CETA also created a separate, new planning requirement called the
clean energy implementation plan (CEIP). The new legislation directed the Commission to issue
rules related to IRPs, which occurred midway through the previous IRP 2019 planning cycle.
Faced with the likelihood the 2019 IRPs may not be fully CETA-compliant, Staff petitioned, and
the Commission ordered, the 2019 IRPs be considered IRP progress reports.1 The Utilities and
Transportation Commission (Commission) initiated rulemakings2 in January 2020 to develop rules that would implement the new law. The IRP and CEIP rules were finalized on December 28, 2020.3 The new rules require IRPs to be submitted on January 1, 2021, and on January 1 every four
years thereafter.4 However, given the changes to the IRP process required by CETA, the
Commission ordered each electric utility (Puget Sound Energy [PSE], Avista Corporation
[Avista], and PacifiCorp) to submit draft 2021 IRPs by January 4, 2021, with the final versions
by April 1, 2021.5
All three utilities filed their draft IRPs on January 4, 2021. Both Avista and PSE filed joint electric and gas IRPs. On January 5, 2021, the Commission issued a notice of opportunity for comment from interested parties in the IRP dockets for these three companies by February 5, 2021.6 The notices also announced recessed open meeting dates and times where the companies will present their draft plans and respond to questions from the Commission and interested stakeholders. The recessed open meeting dates are:
• PacifiCorp: Monday, February 22, 9:30 a.m.
• Avista: Tuesday, February 23, 9:30 a.m.
• PSE: Friday, February 26, 10:30 a.m.

1 PacifiCorp, Docket UE-180259, Order 03, ¶¶ 24-25; Puget Sound Energy, Dockets UE-180607 & UG-180608,
Order 02, ¶ 15 (Puget Sound Energy); Avista, Docket UE-180738, Order 02, ¶ 15.
2 Dockets UE-191023 & UE-190698 (Consolidated), implementing the Clean Energy Transformation Act codified
as RCW 19.405 and changes to RCW 19.280 - Electric Utility Resource Plans. 3 In re Adopting Rules Relating to Clean Energy Implementation Plans and Compliance with the Clean Energy Transformation Act and Amending or Adopting rules relating to WAC 480-100-238, Relating to Integrated Resource Planning, Dockets UE-191023 & UE-109698 (Consolidated), General Order 601, pp. 58-59, ¶ 168 (CETA Rulemaking Order) (Dec. 28, 2020).
4 WAC 480-100-625(1).
5 See supra n.1. 6 Notice of Opportunity to File Written Comments, Avista, Dockets UE-200301 and UG-190724, and UE-200420; Puget Sound Energy, UE-200304 and UG-200305; and PacifiCorp, Docket UE-200420 (Jan. 5, 2021).
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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This appendix is organized by subject area as they appear in the Commission’s rules and
describes the statute and rule requirements that govern the IRP process for both electric and
natural gas IRPs. The main body of Staff’s comments (to which the current document serves as
an appendix) is also organized by subject area, and discusses three things:

• How each IRP meets (or does not meet) the requirements laid out in this appendix;
• Whether each utility’s IRP modeling is consistent with its peers; and
• What changes Staff recommends to enable acknowledgment of the 2021 final IRP and
Clean Energy Action Plan (CEAP), support the development of the Clean Energy
Implementation Plan (CEIP), or in each company’s next IRP.

Overview of Electric IRP Statute and Rule Requirements by Topic

Public Participation

The Commission’s new rules facilitate more opportunities for deeper, cross-topical conversations
between interested persons and utilities on a variety of IRP issues, such as equity, to implement
CETA directives.7 Staff highlights two of these public engagement components: participation
and involvement of the IRP advisory group, and the two-step draft IRP and final IRP submittal,
which will eventually help inform the shape and style of a CEIP. 8

First, to develop an effective IRP, CEAP, two-year progress report, and CEIP, the utility must
demonstrate and document how it considered input from its advisory group, including scenarios
and sensitivities the utility used.9 Throughout the IRP planning processes, it is incumbent upon
each utility to provide staff, the advisory group, and the public meaningful opportunities to
engage and discuss complex resource planning processes, data assumptions, and other topics
such as upstream emissions and the SCGHG emissions used in IRP modeling analyses.

Second, utilities are now required to submit a draft IRP, which provides stakeholders, the media,
and the public a meaningful first glimpse into the utility’s thinking around energy and capacity
resource planning in the post Clean Energy Transformation Act world, before the utility files its final IRP four months later.10 Presenting a draft plan for complex energy and capacity planning is not new. In fact, requiring a mostly complete draft to be filed prior to the issuance of a final document is common practice. For example, the Northwest Power and Conservation Council’s (NWPCC or Council) power plan development process includes a two-stage process of issuing a draft plan, taking public comment, conducting the appropriate analysis to respond to public comment, and issuing a final plan.11 Due to the ongoing COVID-19 public health crisis, the 2021 IRP public participation process
7 WAC 480-100-620; -625; and -630.
8 WAC 480-100-625; WAC 480-100-630; CETA Rulemaking Order at ¶ 137.
9 WAC 480-100-625; -630; and -655. 10 WAC 480-100-625(3). 11 CETA Rulemaking Order at ¶ 166.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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cycle looked very different as compared with previous IRP cycles. Staff is acutely aware the first
post-CETA IRP cycle was decidedly more difficult for all involved, with most advisory group
meetings held virtually via webinar. Plus, the utility faced unprecedented CETA modeling and
timing challenges. Staff comments highlight specific areas of success in the public engagement
arena and potential areas of improvement for future IRP cycles.
Data Disclosure
To comply with CETA, electric utilities should address three primary data disclosure themes during the 2021 IRP cycle. First, companies should provide the information that stakeholders request during the planning process in a timely manner or provide clear justification why the request cannot be met.12 This circulation of information in the development and reporting of IRPs should primarily occur during the advisory group process.13 Adherence to this principle is important as it will align utility planning with the overarching ethos of CETA – one of accessibility, transparency, responsiveness, and clarity. Second, to maximize transparency, the electric utilities must file with the Commission all data input files in native format as appendices to the draft IRPs.14 The Commission, Commission Staff, Public Counsel, and other parties with a substantial interest in a company’s plan must be able to understand a utility’s decisions. Companies disclosing such data in native format facilitates parties independently determining if those actions were in the public interest and represent the lowest reasonable cost option.15 Finally, the data a utility provides during the IRP planning process should be easily accessible.16 Release of such information should be more than large data dumps, whose sheer size can overwhelm the recipients thus reducing the likelihood questions get answered. Instead, companies should tailor the data provided to the requestor’s specific query.17 While utilities can
still designate relevant data confidential in keeping with the Commission’s rules,18 Staff’s
expectation that accessible information is readily shared amongst stakeholders fosters
meaningful and inclusive public engagement throughout the IRP advisory group process.

Load Forecasting and Climate Change Impacts

One of the most critical steps in the IRP analyses involves the assessment of how much total
energy the utility’s customers are expected to consume over a 20-year period (load), including
the maximum amount expected to be consumed instantaneously (peak demand). In the IRP, the
utility must assess projected economic and population growth for the region. Further, recently
updated IRP rules set forth additional requirements in the load forecasting step of the IRP
12 Id., at ¶ 178. 13 WAC 480-100-630(3). 14 WAC 480-100-620(14) requires utilities undertake IRP data disclosure actions suggested in RCW 19.280.030(10)(a).
15 CETA Rulemaking Order at ¶ 173.
16 WAC 480-100-620(14). 17 CETA Rulemaking Order at ¶ 178. 18 WAC 480-07-160.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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development process. These include requiring the utility to conduct a new assessment of
Distributed Energy Resources or DERs, develop climate change scenarios, and other relevant
load assessments.19

In addition to their existing requirement to pursue all cost-effective, reliable, and feasible energy
efficiency, CETA now requires utilities to pursue all “cost-effective, reliable, and feasible”
demand response (DR).20 Thus, utilities must perform forecasts of cost-effective potential of
both resources, where these forecasts must in turn inform the load forecast. Second, CETA requires utilities to conduct an overarching DER forecast, “and an assessment of their effect on the utility’s load.” The Commission’s rules adopted to implement CETA require such forecasts to include energy efficiency, DR, and energy assistance, as well as other DERs like energy storage, electric vehicles (EVs), and solar photovoltaics (PV).21 Finally, risks are changing because of climate change. The recently revised IRP rules require utilities to include at least one future climate change scenario, incorporating “load changes resulting from climate change.”22 As compared to the expected ‘base case’ or ‘do nothing’ portfolio, the utility should also consider load impacts, higher risks of changing river flows, disaster frequency, and temperature effects over time on the utility’s load-resource balance. IRP Modeling Modeling is central to a utility’s resource planning because the IRP is essentially a numerical solution for how the company will keep the lights on in the short- and long-term, addressing resource need and balancing supply and demand, given a host of constraints.23 In determining this IRP solution, the company and stakeholders must examine a range of forecasts and analyses when identifying options for how to meet customer demand, compare these options, and ultimately decide what resources to build or acquire.24 The 2021 IRPs are the utilities’ first
roadmaps for realizing the transformative change required by CETA as these plans couple
modeling with the supporting narrative required to explain companies’ decisions to a wide
stakeholder audience.

Utilities must develop and validate their planning models with additional rigor since electric
IOUs’ 2021 preferred portfolios will establish the baseline for achieving CETA’s coal
elimination, GHG neutral, and clean electricity targets over the next 25 years.25 To comply with
CETA directives and adaptively manage modeling methodologies, utilities must determine how
best to incorporate the social cost of greenhouse gases (SCGHG) into their analytics, properly
integrate distributed energy resource (DER) assessments into resource planning, and undertake
more sophisticated scenario and sensitivity modeling as compared with previous IRP cycles.
These three modeling topics constitute focal points of the 2021 draft IRP staff review.
19 WAC 480-100-620(3) and (10). 20 RCW 19.405.040(6)(a); -.050(3). 21 WAC 480-100-620(3).
22 WAC 480-100-620(10)(b).
23 RCW 19.280.030(1). 24 WAC 480-100-620(11). 25 RCW 19.405.030(1); -.040(1); -.050(1).
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 813 of 1105

As required by statute and rule, utilities must incorporate SCGHG as a cost adder when
evaluating and selecting conservation and resource options. Within their IRP narrative
companies should evaluate the robustness of their analytical approaches and describe how the
IRP solution incorporates the SCGHG cost adder throughout the modeling stages. Appropriately
handling SCGHG within IRP analyses is likely the most important modeling consideration for
utilities during the 2021 cycle as this adder applies across the range of resource strategies
considered.26 Modeling SCGHG also serves as an insightful linkage for comparing how Washington’s three IOUs are pricing new CETA requirements into resource selection. Reflective of CETA, both statute and accompanying rule continue to require the lowest reasonable cost (LRC) solution,27 but are now more prescriptive when it comes to the types of resources, especially clean alternatives, and analyses that must be considered when planning for future targets. Utilities must now consider a wide range of DER options and undertake quantitative methods (e.g., forecasts of demand response and other demand side management) to determine the impact such efforts will have on utility planning.28 Utilities should appropriately incorporate DER potential into portfolio development. Staff’s goal is to ensure appropriate utility valuation of resources like demand response (DR) and energy efficiency (EE), which is crucial to meet CETA standards and implement specific targets identified in the CEIP. Additionally, utilities’ portfolio development must quantify the impact and risk associated with crosscutting concerns like ensuring resource adequacy and equitably distributing customer benefits and costs.29 Companies need to develop a CETA “counter factual” scenario that identifies the alternative LRC portfolio the companies would have implemented if the CETA requirements around greenhouse gas neutrality by 2030 and clean electricity by 2045 were not in effect. Second, companies need to run a climate change scenario that incorporates the best science available to assess climate change impacts, including hydrological conditions,
temperature, and load changes.

Finally, utilities are required to run a sensitivity that examines how their 2021 preferred portfolio
performs when benefits for all customers are maximized, before balancing other objectives.30
This analysis seeks to quantify how all customers, including vulnerable populations or highly
impacted communities, are benefiting from the transition to clean energy.31 The analysis should
only adjust variables specific to an IOU’s Washington service territory. The intent of this
modeling exercise is to maximize the hypothetical benefit utilities’ Washington customers could
realize. There is no “right answer” for how to optimize this benefit so utilities should brainstorm
what activities or actions are most efficacious. Once determined, companies could “hardcode”
given levels of these benefits and subsequently co-optimize other modeling variables. Staff
recognize competing constraints may prevent a company’s 2021 IRP from ultimately reflecting
these sensitivity attributes. For the 2021 IRP, the primary result of this sensitivity is additional
26 RCW 19.280.030(3)(a); WAC 480-100-620(11)(j). 27 RCW 19.280.030(1)(d); WAC 480-100-620(7) and (11)(a).
28 RCW 19.280.030(1)(h) and (j); WAC 480-100-620(3) and (11)(c).
29 RCW 19.280.030(1)(g), (i), and (k); WAC 480-100-620(8), (11)(f) and (g). 30 WAC 480-100-620(10)(a) – (c). 31 RCW 19.405.040(8).
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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data and analyses utilities can further refine for their 2022 CEIP and subsequent planning
cycles.32 Nonenergy Impacts

The IRP statute changes in CETA require the IRP to address the clean energy transformation
standards.33 This results in the need for nonenergy impacts (NEIs) of the utility’s energy system
and programs to be included in the 2021 IRP more prominently as compared with previous IRP cycles. Historically, NEIs were nearly all associated with energy efficiency programs and measures. Under CETA, NEIs should be included with all resources when applicable. Utilities are required to account for nonenergy costs and benefits not fully valued elsewhere in an
IRP model within distributed energy resource assessments.34 For example, a CPA should not
include a separate value for the SCGHG if that value is appropriately accounted for elsewhere in
the selection of energy efficiency. A nonenergy benefit that occurs exclusively or primarily on
the demand-side should be included within the CPA (or other DER assessment). Some values of
nonenergy impacts are well documented in the region, particularly those vetted by the Regional
Technical Forum. However, there are many impacts for which data is currently unavailable, not
monetized, attributable to a program instead of a measure, out-of-date, or not applicable to a
particular utility service territory. In these instances, Staff finds it appropriate to use proxy data
to identify nonenergy costs and benefits.

Finally, nonenergy costs and benefits are required by the new rules to be listed in the avoided
costs section of the IRP and identify if they accrue to utility, customers, participants, vulnerable
populations, highly impacted communities, or the public.35
New Customer Benefit Provisions of CETA The clean energy transformation standards described in rule address the affirmative mandate to ensure all customers are benefiting from the transition to clean energy, identifying three separate components of the customer benefit requirement.36 Each component should be addressed in the IRP in multiple ways. Specifically, the rule requires each utility to include an assessment of economic, health, and environmental burdens and benefits in the IRPs.37 While the cumulative impact analysis (CIA) conducted by the department of health that should inform the assessment was not available in
32 Conservation Energy Planning and Energy Policy staff customer benefit discussion, January 20, 2021. 33 RCW 19.280.030(1) requires an IRP to address the “. . . implementing [of] RCW 19.405.030 through 19.405.050, at the lowest reasonable cost and risk to the utility and its customers, . . .” including an assessment of “Energy and nonenergy benefits and reductions of burdens to vulnerable populations and highly impacted communities; long-term and short-term public health and environmental benefits, costs, and risks; and energy security and risk;”
34 WAC 480-100-620(3).
35 WAC 480-100-620(13). 36 WAC 480-100-610(4)(c)(i)-(iii). 37 WAC 480-100-620(9).
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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time for the 2021 IRP, the requirement that the assessment be informed by the CIA does not
waive the requirement for an assessment if the CIA is unavailable.38 Each utility IRP must
include an assessment of energy and nonenergy benefits and reductions of burdens to vulnerable
populations and highly impacted communities; long-term and short-term public health and
environmental benefits, costs, and risks; and energy security and risk using other sources of
information relevant to the assessment. One use of this assessment is to inform the current
distribution of benefits and burdens within a utility’s service territory.

While it is hard to overstate the impact of CETA’s clean energy mandates, the statute’s customer
benefit provisions are perhaps even more of a divergence from the utilities’ (and the
Commission’s) traditional approaches to system planning and operations. For decades, utilities
have been tasked with building a plan that can meet anticipated system needs at lowest
reasonable cost, considering risk. CETA has added another priority that the utilities must
achieve: ensuring all customers are benefiting from the transition to clean energy.

In future IRPs, this customer benefit mandate will largely focus on customer benefit indicators
(CBIs). However, the utilities’ inaugural CEIPs will emphasize CBI determination and details.39
Instead, the CETA statutory and rule applicable to the 2021 planning cycle covers three topical
areas: current-state assessment of economic, health, and environmental burdens and benefits;40
maximum customer benefit modeling sensitivity discussed above;41 and each utility’s formation
of an equity advisory group.42

The new economic, health, and environmental burdens and benefits assessment includes
developing a current-state “snapshot” of the energy impacts and NEIs vulnerable populations and
highly impacted communities experience within the electric IOUs’ Washington service
territories. Similarly, the IRP also needs to consider risks associated with long-term and short-
term public health and environmental impacts as well as energy security.43 These current
conditions are the basis for determining whether the allocation of benefits and burdens from the
utility’s transition to clean energy results in equitable distribution.44 This current-state
assessment is critical for establishing baseline geographic and demographic datapoints, including
identifying the vulnerable populations and highly impacted communities a given utility serves.45
While the original intent was for electric IOUs to consider the Washington Department of
Health’s cumulative impact analysis (CIA) in developing their assessments,46 the CIA’s delay
past December 31, 2020, does not waive the assessment requirement. Utilities should consider
38 CETA Rulemaking Order at ¶ 54. 39 WAC 480-100-640(4). 40 WAC 480-100-620(9). 41 WAC 480-100-620(10)(c). 42 WAC 480-100-625(2)(b), WAC 480-100-655(1)(b).
43 WAC 480-100-620(9).
44 CETA Rulemaking Order at ¶ 53. 45 See WAC 480-100-605 for definitions of “highly impacted community” and “vulnerable populations.” 46 RCW 19.280.030(1)(k).
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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alternative references (e.g., U.S. Census data) relevant to the assessment.47 Each electric utility
must provide this assessment as part of its 2021 IRP to comply with CETA.48

Lastly, the equity advisory group required for utilities’ forthcoming CEIPs should also inform
IRP planning.49 In this fashion, an IOU’s comprehensive attention to vulnerable populations and
highly impacted communities serve as a common thread linking successive CETA deliverables
(i.e., IRPs, CEAPs, CEIPs).50 Hence, each company should create an equity advisory group by
May 1, 2021, to provide useful and timely input for the planning cycle. Further, this advisory
group must be Washington-focused, comprised of Washington stakeholders, and include
representatives from highly impacted communities and vulnerable populations. A multi-state
utility cannot simply apply a systemwide advisory group to also serve as the company’s equity
advisory group to comply with CETA.

Conservation and CPA
The Energy Independence Act (EIA) (RCW 19.285) was not replaced or modified by the passage
of CETA. When the activities undertaken to comply with the EIA meet the requirements of
CETA, they qualify for compliance with both statutes. Staff expects that the customer benefit
mandate, with its provisions to account for additional nonenergy impacts such as public health
benefits, and requirement to reduce of burdens to vulnerable populations and highly impacted
communities, will make additional energy efficiency a cost-effective resource choice.

The new IRP rule requires an energy efficiency and conservation potential assessment of current and potential policies and programs needed to obtain all cost-effective conservation, efficiency, and load management improvements; including the ten-year conservation potential used in calculating a biennial conservation target under WAC 480-109.51 This requirement should not change utility standard practice to any real degree. Staff expects that incremental improvements to the potential assessment are ongoing. Each IRP should, at minimum, provide sufficient data points to calculate the ten-year, four-year, and two-year cost-effective conservation potential under both CETA and the EIA. Demand Response The IRP must contain a demand response potential assessment of current and potential policies and programs needed to obtain all cost-effective demand response.52 The statutory definition of demand response is broad and includes pricing structures (such as time of use or critical peak pricing), measure-based programs controlled by the utility, and behavioral programs that include
47 CETA Rulemaking Order at ¶ 54. 48 Conservation Energy Planning and Energy Policy staff customer benefit discussion, January 20, 2021.
49 WAC 480-100-625(2)(b), WAC 480-100-655(1)(b).
50 CETA Rulemaking Order at ¶ 162. 51 WAC 480-100-620(3)(b)(i). 52 WAC 480-100-620(3)(b)(ii).
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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an incentive payment.53 In order to determine all cost-effective demand response as required by
CETA, a potential assessment must include a broad range of options that include each of these
types of demand response.54
Energy Storage

Energy storage is identified in CETA and in the recently adopted WAC rules implementing
CETA as a key component of the transition to clean energy.55 Energy storage can address many
types of system needs: energy, capacity, ancillary services, integration of renewable resources,
balancing, spinning and non-spinning reserves, and emergency power. Energy storage can also
play a role in deferring or preventing some transmission and distribution projects. The newly
adopted WAC includes the following requirements related to energy storage:

• WAC 480-100-605 – energy storage included in definition of a DER.
• WAC 480-100-620(3)(a) – DER assessments in a utility’s IRP “must incorporate nonenergy costs and benefits not fully valued elsewhere within any integrated resource plan model.”
• WAC 480-100-620(3)(b)(iv) – storage identified as a DER “that may be installed by the
utility or the utility’s customers,” and which the “IRP must assess[.]”
• WAC 480-100-620(5) – battery and pump storage identified as potential way to
integrate renewable resources and address overgeneration events.
• WAC 480-100-620(11)(e) – acquisitions made after CETA’s passage must “rely on renewable resources and energy storage, insofar as doing so is at the lowest reasonable cost.”
While CETA has changed the regulatory landscape in Washington, energy storage is not new to the Commission.56 Accurate modeling and optimal use of energy storage within a utility’s system planning tools was identified as the main limitation to full consideration of energy storage as a resource in the Commission’s policy statement. The value of energy storage is more apparent when a system planning model uses a granular timescale – the more granular the modeling timescale, such as an hourly or sub-hourly dispatch simulation, the more value of energy storage can be identified. Many IRP modeling tools’ optimizations are not typically performed on an hourly or sub-hourly basis. In the policy statement, the Commission also discussed policy principles related to energy
53 "Demand response" means changes in electric usage by demand-side resources from their normal consumption
patterns in response to changes in the price of electricity, or to incentive payments designed to induce lower
electricity use, at times of high wholesale market prices or when system reliability is jeopardized. "Demand response" may include measures to increase or decrease electricity production on the customer's side of the meter in response to incentive payments. 54 WAC 480-100-610(4)(a). 55 RCW 19.405.040(6)(a)(iii); RCW 19.405.050(3)(c); WAC 480-100-620(11)(e).
56 Report and Policy Statement on Treatment of Energy Storage Technologies in Integrated Resource Planning and Resource Acquisition, Dockets UE-151069 and U-161024, ¶ 15 (Oct. 11, 2017) (Policy statement identified ”barriers that prevent energy storage from being fairly considered in resource planning and develop[ed] policies to overcome them”).
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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storage, many of which are also reflected in the newly adopted Part VIII of Chapter 480-100
WAC. We briefly summarize some components of the policy statement that continue to be
relevant in the context of CETA and the revised WAC:

• Utilities should move toward a “new planning framework that more cohesively considers the relationship between generation, transmission, and distribution, allowing for a fair evaluation of hybrid resources such as energy storage.”57
• Utilities should adopt modeling platforms capable of sub-hourly modeling, and in the
interim should use an external model capable of modeling the sub-hourly benefits of storage over the resource’s useful life, including transmission and distribution benefits, then calculate the net present value of those benefits and deduct that value from the resource’s modeled capital cost in the IRP.”58
• Utilities should consider at least “a reasonable, representative range of storage
technologies and chemistries,” working with their advisory groups to identify these
resources, 59
• Utilities should vet storage cost assumptions by reviewing third-party data and applying
“a reasonable learning curve to storage costs to account for forecasted declines.”60
• Finally, utilities should ensure that storage is considered in evaluating distribution system projects, including all locational benefits.61 As utilities use resource modeling software that is more sophisticated as compared with previous IRP cycles, and as CETA’s equity components are better understood, Staff expects that the importance of energy storage as a resource that can address multiple system needs and inequities will only grow, as will Staff’s focus on its accurate modeling and full consideration in each utility’s IRP. Qualifying Facilities – Avoided Cost Methodology The Public Utilities Regulatory Policies Act, or PURPA, requires utilities to purchase energy and capacity made available to them by qualified facilities (QFs) at a price based on the utility’s avoided costs.62 The IRP estimates what the utility’s system needs, and at what cost. The goals
of making avoided costs understandable for all stakeholders and of strengthening the connection
between the IRP analysis and PURPA rates were both key factors driving the adoption of the
new WAC 480-100-620(13) and (15).

57 Id. at ¶ 36.
58 Id. at ¶ 43.
59 Id. at ¶ 46. 60 Id. at ¶ 47 61 Id. at ¶ 48. 62 The Commission revised its implementation of PURPA recently through a rulemaking that culminated in Chapter 480-106 WAC, which prescribes a methodology for setting PURPA rates for QFs with a nameplate capacity of 5
MW or less, and which requires that utilities file for the Commission‘s consideration and approval a methodology to
calculate avoided cost rates QFs larger than 5 MW. These methodologies were submitted by all three utilities and approved by the Commission in the following dockets: UE-191062 for PSE, UE-200455 for Avista, and UE-200573 for PacifiCorp.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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• WAC 480-100-620(13): “Avoided cost and nonenergy impacts. The IRP must include an analysis and summary of the avoided cost estimate for energy, capacity, transmission, distribution, and greenhouse gas emissions costs. The utility must list nonenergy costs and benefits addressed in the IRP and should specify if they accrue to the utility, customers, participants, vulnerable populations, highly impacted communities, or the general public. The utility may provide this content as an appendix.”
• WAC 480-100-620(15): “Information relating to purchases of electricity from
qualifying facilities. Each utility must provide information and analysis that it will use to inform its annual filings required under chapter 480-106 WAC. The detailed analysis must include, but is not limited to, the following components:
(a) A description of the methodology used to calculate estimates of the avoided
cost of energy, capacity, transmission, distribution and emissions averaged
across the utility; and
(b) Resource assumptions and market forecasts used in the utility's schedule of
estimated avoided cost required in WAC 480-106-040 including, but not limited
to, cost assumptions, production estimates, peak capacity contribution estimates
and annual capacity factor estimates.”

Resource Adequacy and Uncertainty Analysis

Resource adequacy (RA) studies in the IRP, including RA metrics and methodologies, are
extremely important to ensure the lights stay on. Specifically, CETA requires an electric utility’s
IRP to determine “resource adequacy metrics for the resource plan” and to identify “an
appropriate resource adequacy requirement and measurement metric consistent with prudent
utility practice.”63 Staff’s review of resource adequacy in the IRP is broad in scope and involves
all aspects of load service and modeling, including: energy, capacity, flexibility, availability, and
performance characteristics of specific resources, such as demand-side, storage, wind resources,
and batteries.64 The analysis of the contribution to RA by storage and variable energy resources
is of particular interest to Staff in the first post-CETA IRP review. Staff comments also address
the incorporation of uncertainty into the RA assessment, often in the form of sensitivity analysis. Distribution Planning Process

The IRP rules require that the utility must include assessments of a variety of distributed energy
resources and the effect of distributed energy resources on the utility's load and operations.65
Further, the commission strongly encourages utilities to engage in a distributed energy resource planning process as described in RCW 19.280.100. If the utility elects to use a distributed energy resource planning process, the IRP should include a summary of these results.
63 See RCW 19.280.030(1)(g) and (i). 64 WAC 480-100-620(8). 65 WAC 480-100-620(3).
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 820 of 1105
Overview of Clean Energy Action Plan (CEAP) Requirements
To comply with statute and rules, each utility must develop a ten-year clean energy action plan
that works toward implementing the IRP’s lowest reasonable cost solution, including
incorporation of the social cost of greenhouse gas emissions as a cost adder in its analysis.66 As
the intermediary plan between the IRP and the CEIP, the CEAP should identify the utility’s ten-
year resource “ramp” needed to meet energy, capacity, and associated flexibility in order to
maintain and protect safe, reliable operation and balancing of the electric system, while
achieving other clean energy transformation objectives.67 Specifically, each CEAP should:

• meet clean energy transformation standards, including customer benefit provisions68;
• be informed by the utility’s ten-year cost-effective conservation potential assessment;
• identify the potential cost-effective demand response and load management programs that may be acquired;
• establish a resource adequacy requirement and demonstrate how each resource, including
renewable, nonemitting, and DERs, may reasonably be expected to contribute to meeting
the utility’s resource adequacy requirement;
• identify any need to develop new, or to expand or upgrade existing, bulk transmission
and distribution facilities; and
• identify the nature and extent to which the utility intends to rely on an alternative compliance option identified under RCW 19.405.040(1)(b), if appropriate.
Overview of Natural Gas IRP Statute and Rule Requirements by Topic
Design Day (Planning Standard), particularly in the context of climate change data or future studies “Design day” refers to the peak temperature assumption that natural gas local distribution companies (LDCs) use to develop the plan for their natural gas supply and distribution pipeline systems. Neither statute nor rule impose any specific requirements for design day in the natural gas IRPs. Each LDC has the flexibility to identify its design day as appropriate. The utility must include the design day in its natural gas IRP, and provide a discussion justifying its selection, particularly addressing climate change risk of gradually increasing temperatures over time. Upstream Emissions & SCGHG For the first time, statute requires LDCs to model a price on greenhouse gas emissions in the IRP. The statute specifies the price assigned to these emissions, but only for the purposes of
66 WAC 480-100-620(12). 67 WAC 480-100-610(4)(b). 68 WAC 480-100-610.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 821 of 1105
setting conservation targets.69 That price is set at the social cost of greenhouse gases (SCGHG),
using a 2.5 percent discount rate, where the utility must also model and account for upstream
emissions or “emissions occurring in the gathering, transmission, and distribution of natural gas
to the end user.”

CPA and Conservation Targets RCW 80.28.380 requires gas companies to identify and acquire all conservation measures that are available and cost-effective, with an acquisition target approved by the commission every two years beginning in 2022. The target will be reviewed with the next conservation plan, but the IRP will be a main source of the data. A determination of cost-effective conservation in the IRP will be the start of the target calculation and must be clearly included in the IRP. The cost-effectiveness analysis required by this section must include the costs of greenhouse gas emissions established in RCW 80.28.395. This could be included in the CPA or in a different IRP model. The IRP must include a clear description of how and where the SCGHG is included.
The targets must be based on a conservation potential assessment (CPA) prepared by an
independent third party and approved by the commission. In order for Staff to recommend the
commission approve a CPA there must be:

1. Transparent review of model. 2. Vetting through advisory groups. 3. Consistency with the Council’s method. 4. Internal consistency with load forecast. While it has been the practice of the utilities to exclude gas transportation customers from participating in their conservation programs, Staff struggles to find an exclusion for gas
transportation customers in the statutory language of RCW 80.28.380. Thus, in order to identify
all cost-effective conservation, it will be necessary for the utility to separately consider and
evaluate the energy efficiency potential of any customers too large to include in the CPA.70 All
available and cost-effective conservation potential must be included. The method chosen should
be discussed with the advisory groups. Staff expects that if this conservation from large
industrial customers is included in the IRP analysis, it is likely to reduce the utility’s need for
distribution system improvements.

Renewable Natural Gas (RNG)

Natural gas LDCs “must” offer their customers a voluntary RNG service by tariff.71 Such service
69 RCW 80.28.395. The conservation targets for LDCs are also a new requirement: HB 1257 for the first time requires LDCs to identify and acquire all cost-effective conservation and requires them to set two-year acquisition targets that will accomplish this goal. RCW 80.28.380.
70 Potential assessments assume average market penetration and savings over sizeable populations. Conservation
potential from large industrial customers, including transportation customers, are more appropriately treated individually than on an average basis. 71 RCW 80.28.390.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 822 of 1105
would “replace any portion of the natural gas that would otherwise be provided by the gas
company.” Second, LDCs “may” propose an RNG program that “would supply renewable
natural gas for a portion of the natural gas sold or delivered to its retail customers.”72 These two
provisions contain an important distinction: The first requires LDCs to offer RNG to those
customers that want it, while the second allows them to offer an RNG program that would serve
all customers. The latter is subject to cost and environmental limitations. Analysis in the IRP will
support the utility’s proposals in this area. Further, the utility’s IRP must discuss its plans
concerning RNG. Storage WAC 480-90-238(3) requires LDCs to “assess” opportunities to use company-owned or contracted storage in their IRPs, and also includes storage options as one of many resource options to be evaluated using a “consistent method to calculate cost-effectiveness.” Distribution Planning
Each LDC must provide a short-term plan outlining the specific actions to be taken to implement the long-range integrated resource plan during the two years following submission.73 Each LDC also typically outlines a multi-year budget for engineering projects through a distribution scenario decision-making process. LDCs identify areas with growth forecasted to create capacity issues, focusing on areas for future improved distribution capacity needs, and highlight these projects in the IRP.
72 RCW 80.28.385. 73 WAC 480-90-238(3)(h).
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 823 of 1105
1
Gall, James
From:Andrew Argetsinger <[e-mail]>
Sent:Tuesday, February 16, 2021 4:31 PM
To:Lyons, John; Gall, James
Cc:Kevin Calhoon; Stuart McCausland
Subject:[External] RE: Avista's Draft 2021 Electric IRP
John / James – Hope all is well. We are reviewing the current draft of the 2021 IRP and had a few questions:

(1) We noticed that there was not a Lancaster PPA extension scenario included in the 2021 draft IRP. Why the
change from last year?
(2) Would you consider revising this draft to include a 10 year Lancaster PPA extension scenario? It seems unlikely
to us that choosing not to extend the Lancaster PPA and turning around to immediately add 210+ MW of new
peaking capacity in 2027 would be economically advantageous enough (compared to a Lancaster PPA extension
scenario) to exclude the extension scenario from the IRP.
(3) Will you share with us the unit parameters for Lancaster that would be used for a Lancaster PPA extension
scenario? We’d like to understand what level of operational flexibility would be assumed in a Lancaster PPA
extension scenario.

Please let me know if you have any questions or clarifications regarding these requests.

Best,

Andrew Argetsinger
Senior Director, Corporate Strategy
Tyr Energy, Inc.
7500 College Blvd., Ste. 400
Overland Park, KS 66210
913.626.0772 (mobile)
[e-mail]

From: Lyons, John <[e-mail]>
Sent: Monday, January 4, 2021 5:20 PM
To:
Subject: Avista's Draft 2021 Electric IRP

CAUTION: This email originated from outside your organization. Exercise caution when opening attachments or clicking
links, especially from unknown senders.
Hello TAC Members,

Attached is a copy of the draft 2021 Electric IRP for your review. Please provide any comments or edits back to us by
Monday, March 1, 2021 to me at [e-mail]. The final IRP and completed appendices will be filed on
April 1, 2021 with the Idaho and Washington Commissions.

Our fifth and final TAC meeting will be held on Thursday, January 21, 2021. The meeting invitation and agenda will be
available by the end of this week. There will also be an opportunity to provide written comments about the draft IRP to
the Washington Commission and a public meeting on February 23, 2020. We will provide more details at the fifth TAC
meeting.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 824 of 1105
2
Thank you for all of your participation in the 2021 IRP,

John Lyons
Avista Corp.
509-495-8515

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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 825 of 1105
November 14, 2020
To: John Lyons, John Barber, Dennis Vermillion, IPUC, WPUC & TAC committee members
From: Dave Van Hersett, TAC Member Emeritus
Subject: Biomass Generation omitted from considered IRP Options
Just read the draft IRP and found that Biomass Generation has been omitted from considered
options for analysis. We have a substantial renewable biomass fuel supply in our Inland
Empire. We should utilize it for the good of man rather than fuel for forest fires. So here is the
case for Biomass Generation to provide new generation that meets CETA and brings back the
forest products industry to the Inland Empire.
1. CETA approved three options for new power generation, Wind, Solar and Biomass.
2. Kettle Falls 50 MW Biomass generation plant has been operating since the early 80’s
utilizing sawmill biomass fuels generated during the processing of round logs to make
rectangular lumber and other products.
3. The logging process does not utilize the tops and branches of the tree. The tops and
branches equal the weight of the saw logs delivered to the sawmill.
4. Sawmill biomass fuel is ten percent of the weight of the saw logs brought into the
sawmill.
5. The tops and branches weigh ten times the weight of the sawmill biomass fuel. This
ratio is dependent on type and specie of forest growth.
6. Since the 50 MW Kettle falls Biomass power plant utilizes sawmill biomass fuels, the
tops and branches logging biomass would have enough fuel for 500 MW of biomass
generation.
7. Biomass fueled generation works when the sun does not shine and works when the
wind is not blowing and can be scheduled to meet the load profile of the customers.
Thus, less generation capacity is needed due to load factors of Wind and Solar to meet
given customer loads.
8. Avista has the experience and trained staff to operate thermal biomass power
generation plants.
9. Note that every year Logging fuels are left in the forest to rot and/or be fuels for forest
fires. This is because the trees grow every year independent of politics. Forest fuels are
a renewable bioenergy resource. We have been wasting this energy source for years.
Utilizing Logging Biofuels would reduce the fuel available for forest fires. Utilizing Logging
biofuels would provide excellent forest management practices to optimize the production of
timber products for the good of mankind. Eliminating forest fire fuels would bring back timber
supplies to the 11 former sawmill towns in the Inland Empire. Bringing back the forest products
industry would bring back jobs needed for the ever-increasing population (2% per year).
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 826 of 1105
Both Wind and Solar receive financial incentives to make them competitive with existing
generation resources. Biomass fuels should qualify for the same incentives. These incentives
would then improve the cost of recovering the logging biofuels and delivering them to one or
more power plant locations. The assumption here is that the wind and solar resource utilized in
the draft IRP will continue to receive incentives.
A typical sawmill supports a 5 MW biomass power plant utilizing sawmill biomass fuel. Thus,
each sawmill’s logging biofuels would support a 50 MW biomass power plant utilizing logging
biofuels. This would minimize fuel transportation expense. Integrating 55 MW into the local
electrical distribution system would be easier than one 500 MW power plant.
As the demand for wind and solar increases, the supply of these resources will be subject to the
market demand. The price of wind and solar will likely increase as demand increases and
delivery extended. Biomass fueled power plants are readily available today from several
experienced builders and contractors.
From an operating perspective, Avista could go into partnerships with the sawmills, building
and operating the biomass power plants. The sawmills would provide fuel and utilize steam for
their dry kiln operations. Timber from area forests has been for hundreds of years assuring a
firm fuel supply. Sawmills have been operating in this area since the 1800’s and will continue to
operate as long as the ever-growing population requires timber products for their use. In the
recent 40 years the supply of timber has been subject to politics and the degrading of forest
management practices.
The above concept would be like the former TWWPCO management committing to the
development and investing in hydro and fossil fuel power plants to insure a reliable and low-
cost power cost for its customers. TWWPCO sold excess capacity until it was needed for its
own customers loads.
Biomass generation option should be included as one of the alternatives
evaluated to determine relative economics of the three approved new
generation types, wind, solar and biomass here in the Inland Empire. We have
the moral obligation to utilize the forests for the benefit of mankind not to fuel
forest fires to destroy property and kill our neighbors.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 827 of 1105
Guest Commentary
THE GREEN OPPORTUNITY: Executive Summary
The 40-year Green movement has brought devastation to the forests, destruction
to property and death to inhabitants and created 11 sawmill ghost towns in the
Inland Empire. In 2020 the Conservation Energy Transformation Act (CETA) was
enacting into law providing the key ingredient enabling complete recovery from
40 years of devastation. This act requires that any new electric generation be
from Wind, Solar and BIOMASS. Biomass is wood fuel remaining from harvesting
forests to make products for mankind. We now can bring back the vibrant forest,
clean air, and return the forest products industry and jobs for the inhabitants of
the Inland Empire.
A little history: When I grew up in Spokane in the 50’s I do not remember smoke
filled skies at the lake in the summer. We had lots of towns participating in the
Lilac Parade, logging contests, and fun high school games all around the area.
I remember EXPO 74. All the rides and summer entertainment it brought. EXPO
74 brought the River Front Park that cleaned up the town and provide a major
improvement to the Spokane downtown. This came about from the foresight and
leadership of local businesses and government at the time. No smoke-filled skies
during the EXPO.
Now it is time for our current leadership to take advantage of the enabling CETA
law to bring back our forest products industry and the 30,000 or so jobs with it.
We need this to provide employment for our children and our ever-growing
population. We need to utilize our forests for the benefit of mankind rather than
fuel for forest fires and to clean up the air.
BIOMASS FOREST RESOURCES is our solution!
A BIOMASS project is an electric generating plant that uses wood waste for fuel
instead of fossil fuels. The Kettle Falls 50 Megawatt Biomass fueled power plant
has been operating since the 1980’s. What do we have to do to make this
happen?

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 828 of 1105
First, we have to educate our local governments, our captains of industry, our
utility leadership, and our congressional representatives on the biomass recovery
opportunity that is here today. Then they must put their heads and resources
together for the betterment of its citizens and the husbanding of our local forest
resources.
Second, we have to pre-license Biomass Project sites at the former sawmill towns.
These sites are in the logical locations to minimize the cost of the transportation
of the forest harvested products. These sites will receive a very enthusiastic
approval from the occupants of the former mill towns. Pre-licensing sites will
prove that the public has an extremely high approval of biomass electric
generation. Pre-licensing sites will verify the acceptance of utilization of the local
forests for the benefit of mankind rather than fuel for forest fires. The local
utilities have the skills and resources to accomplish this.
Third, the forest management practices must be changed to allow the use of
timber for products for mankind instead of growing fuel for forest fires. This will
require the assistance of our congressional representatives to make changes to
US Forest Service and State forest management practices.
Fourth, the utilities in this area must require that Biomass be their preferred new
generation resource instead of Wind and Solar. They must incorporate the
benefits of the renewed 10,000 mill jobs and supporting 30,000 jobs in our area
into their financial evaluations when comparing to the Wind and Solar options.
The infrastructure for the utility distribution systems remains in place from the
days of the operating sawmills. No major transmission systems are needed as
compared to Wind and Solar. Benefits from the Biomass investment to the local
area would include more jobs, more tax basis to support local government and
schools, reduction in forest fire prevention and recovery costs, and cleaner air to
name a few.
Finally, bringing back the forest products industry will create a major economic
boon to the Inland Empire. As our population grows our children will not have to
leave the area to find employment. Our region’s natural resource will be
returned to be used to benefit mankind. The forest and our population grow
every year independent of politics.
Bringing back the forest products industry will be our legacy!!
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 829 of 1105
Now for more detail:
Consequences of Going Green
The consequences of going green for the past 40 years are as follows:
1. More fuel for forest fires, property destruction and killing persons.
2. Loss of timber supplies for local sawmills.
3. Lost jobs for the inland empire population.
4. Loss of land for growing food.
5. Loss of scenery viewing from wind and solar.
6. Loss of investment in Inland Empire towns.
7. Loss of tax revenue to support local schools and government.
8. Double to triple electric rates.
9. Triple the generation capacity installed needed to meet customer loads.
10. Increased mining of resources over traditional generation to provide
materials to manufacture and build wind and solar.
11. Loss of birds. Wind power plants kill 30% of the bird population from blade
strikes.
Reflections of a lifetime
Author: A 5th generation of Spokanite, 82-year-old, Veteran, Retired Professional
Engineer, businessman, four great children, Jaycee, Rotarian, Eagle Scout, Scout
Master, Soccer Coach, Spokane School District Citizens Advisory Committee, 50-
year home owner in Spokane, NCHS graduate, WSU BSME & MBA. Career in coal,
oil, natural gas and biomass fueled Power Plant Development and performance-
based Energy Conservation in the commercial, industrial and institutional sectors.
I am 82 now in my twilight and have limited time left to pass on my observations
of a lifetime. My classmates are showing up in an ever-increasing number in the
obituary notices daily. Time is getting short for me give something back. I am a
product of the values of our area and the education system provided by our
citizens. My name is Dave Van Hersett, SR., a proud Spokane citizen.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 830 of 1105
INLAND EMPIRE NATURAL RESOURCES
We have been blessed with the following natural resources in our area to manage
and harvest for the benefit of mankind. They are (1) Water, (2) Mineral resources
underground, (3) farmlands to produce food, (4) forests to grow products for
mankind and finally, our (5) population. We need to husband each of the
resources to support our ever-growing population.
Our forefathers found minerals, gold, silver & lead in the Kellogg wilderness.
Timber from the forests built the railroads to ship the minerals to markets.
Timber provided housing and heat for the population. Water was used to make
electric power to enable mining, industry and support the population. We enjoy
the benefits of our predecessors efforts.
AVISTA ABANDONED THE MAJORITY:
Since renaming The Washington Water Power Company to Avista we customers
have increased the officers compensation from hundreds of thousands to
millions. This makes their compensation ten times that of the President of the
USA and the Gov of Washington State. The average income of Avista customers
is $40,000 per year, about 100 times less than the Avista management
compensation. For what we customers pay Avista management, we expect that
they can accomplish the impossible like Superman and make real improvements
for their 300,000 customers. So, what has the Avista MGT done for its
customers?
(1) They have adopted a strategy to increase the customer monthly billing by
up to three times.
They took their knee to the Green movement indifferent to the will of majority of
its customers. 99% of the customers chose not to participate in Avista’s option’s
to purchase higher cost wind and solar power. The customers gave an
extraordinarily strong signal that they want reliable and low-cost electrical power.
The Avista Utility 20 year plan for generation removes fossil fuel generation and
adds wind and solar. The utility has not come up with any plans to develop
additional revenue to offset the huge increase coming to our energy costs and
bills.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 831 of 1105
(2) They abandoned their Forest Products industry
The result is the creation of 11 ghost towns from the loss of the sawmills in these
towns. These natural forest industries were one of the reasons that founded the
WWP over 100 years ago in 1889. The forest products industry has been
abandoned to grow fuel for forest fires instead of products for mankind. This
accounts for a loss of over 10,000 forest industry jobs and the 30,000 people
supporting the forest products industry in Avista’s service area. Where do these
people go now? Our children leave the area to find employment. To get an idea
of the impact on our forest products towns compare the vibrant town of Colville
with former sawmill towns like Usk, Cusick, Republic, Kellogg, Athol to name a
few.
(3) Tried to sell the utility two times.
Washington and Idaho Utility Commissions did not approve these sales. In both
cases the management would have received a substantial sale commission. I was
never in favor of selling our utility.

Historical Innovation and Leadership in Inland Empire
We enjoy the benefits of our forefathers innovation and leadership to bring
benefits to the local economy and provide employment of our population. In the
1889 The Washington Water Power Company was formed to provide power and
energy to the industries of the time, timber, mining and agriculture. Hydro power
was developed to provide low cost and reliable energy for the ever-growing
industry and populations of this region. Noxon and Cabinet Hydro power projects
were developed to serve the ever-increasing population and industrial customers.
The 1400 MW Centralia Coal Plant and Coal Strip projects were partnered in to
provide reliable and low-cost power for the ever-growing customer loads. Excess
power was sold to other utilities here in the PNW to keep our energy costs low.
In the 70’s TWWPCO developed the Kettle Falls 50 megawatt Biomass Power
Plant utilizing sawmill wood waste that was disposed of in sawmill teepee burners
smoking up the air. This biomass project provided a waste disposal solution for
the forest products industry in the Inland Empire. This plant is operating today.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 832 of 1105
Proposed Action Plan to offset higher energy costs:
In 2020 WA legislature passed a law that requires the utilities to eliminate the use
of plentiful fossil fuels to provide electric power to its customers. It is called the
Clean Energy Transformation Act (CETA). Eliminating fossil fuel generation will
triple our electric rates. The approved new electric generation resources are
Wind, Solar and Biomass.
CETA creates the opportunity to develop up to 750 MW of renewable biomass
generation utilizing our regions biofuels from the improved management of our
region’s forests. Excess generation would be sold to offset the increase in power
costs from the adoption of wind and solar generation in place of low cost and
reliable fossil fueled power generation. This similar to selling our excess hydro
generation until needed for our customers. These biomass projects would also
bring back thousands of jobs to the abandoned forest products industry and
revive the ghost towns in our area. The infrastructure for these ghost towns is
still in place so the incremental revenue benefits would again benefit the
customers.
Develop Renewable Bioenergy Power Plants like Kettle Falls. Install 5 to 10 MW
wood fueled power plants at each of the 11 ghost towns former sawmills and 50
MW like Kettle Falls Power Plant at each of these ghost towns to bring back the
forest products industry. Initiate an aggressive program to clean up the forests in
our area due to the lack of management for the past 40 years. Refer to the
Vaagen Brothers web site to see what a managed forest looks like. Cleaning up
the forest floor will bring biomass fuels along with the residue from logging
operations. There is some 750 MW of biofuels for renewable electric generation
available from the forests in the Inland Empire.
Solicit the help from our congresswoman, Kathy McMorris Rodgers to change
federal laws to enable the forest management practices to support utilizing
biomass for benefit of mankind instead for fuel for forest fires. We need jobs for
our population, we do not want to destroy forests, property or kill persons.
Developing these generation resources will give us the ability to sell excess
energy to the other areas in WA state that will have to meet the 2005 date
required by CETA regulation passed by our Legislature. The sale of this renewable
energy will offset the higher cost of wind and solar such that our electric rates will
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 833 of 1105
not increase three times. This development effort will also bring 10,000 forest
products jobs and their supporting 30,000 population back to our area and reduce
the fuel available for forest fires. We will go back to the notion of raising trees to
produce products for the ever-increasing population and not for fuel for forest
fires. Let’s provide jobs for our children instead of forcing them to leave our area
for employment.
Pre-license Biomass Project sites
Development of Biomass generation requires more effort than wind and solar.
Biomass plants utilizing forest residues will require changes to forest
management practices, changes to new generation priorities, enacting legislative
changes and changes to forest industry logging practices. This is in addition to the
more complicated Environmental Impact Statements and a mirid of permits from
multiple agencies. Our utility management can make these changes happen for
the benefit of their customers. It is easier to develop wind and solar as you only
need vacant land.
Wind and solar benefit from the government incentives to reduce their net
generation costs to compete with fossil fuel generation. These same financial
incentives should be made available to Biomass Generation. The utility should be
working to make this happen.
To make Biomass electric generation possible, the utilities pre-license plants sites
would enable biomass project contractors to be competitive with wind and solar
proposals. Pre-licensing will eliminate the unknown from their proposals and
allow them to focus on what they do best, build power plants. Thus, we would get
competitive prices and that is good for the customers and the region forests.
Renewable generation from Garbage.
Populations generate garbage, a fuel. The fuel heating value of garbage is the
same as forest fuels. Each person generates about 1 ton of garbage per year.
Thus the 500,000 persons in our area generate about 500,000 tons of fuel per
year, enough for 50 MW of power. The city of Spokane uses about 300 MW of
electric power. We have an existing 25 MW at the waste-to-energy plant at the
Spokane Airport. There is enough unused fuel in our area for an additional 25
MW from Spokane County and Coeur’ d Alene’s garbage.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 834 of 1105
Right now, the extra non burned garbage is hauled 210 miles by truck to
Roosevelt, Washington landfill. This creates land that is unusable for decades. A
local example of this is the former land fill you can see south of the I-90 at Liberty
Lake. The vacant land between the apartment units on the hill is a former land fill
site.

TIME FOR OUR LEADERSHIP TO STEP UP AND CREATE A LEGACY
Only once in your lifetime do you get the opportunity to really create a legacy
that will stand the test of time. Bringing back the forest products industry to
the Inland Empire is one of those unique opportunities. Our home grown talent
can make this happen just like our predecessors. We ,the customers, will all
benefit from this effort and like our predecessors you will have the gratitude of
your fellow men and women forever. This task will not be easy. It will take the
cooperative efforts of all of us to make it happen. So let us be like our
predecessors who against all odds, made legacies like mining, hydro power,
forest products industry, EXPO 74 to name a few.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 835 of 1105

2021 Electric Integrated
Resource Plan

Appendix D – Confidential
Historical Generation Operation
Data

Idaho – Confidential pursuant to Sections 74-109, Idaho Code
Washington – Confidential per WAC 480-07-160

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 836 of 1105

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 837 of 1105

2021 Electric Integrated
Resource Plan

Appendix E – AEG Conservation
Potential & Demand Response
Potential Assessments

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 838 of 1105

Energy Solutions. Delivered.
AVISTA CONSERVATION POTENTIAL
ASSESSMENT FOR 2022-2045
De cember 1 , 2020
AVISTA CORPORATION
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 839 of 1105

This work was performed by Applied Energy Group, Inc. (AEG) 500 Ygnacio Valley Rd, Suite 250 Walnut Creek, CA 94596
Project Director: E. Morris
Project Manager: K. Walter
Project Team: G. Wroblewski M. McBride
K. Marrin T. Williams

AEG would also like to acknowledge the contributions of R. Finesilver
L. Haley
J. Gall
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 840 of 1105
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 841 of 1105
CONTENTS
1 INT RODUCTI ON....................................................................................................... 9
Abbreviations and Acronyms .................................................................................. 10
2 ANALYS IS APPROACH AND D ATA DEVEL OPMENT ................................................. 13
Ov erview of Analysis Approach............................................................................... 13
LoadMAP Model ......................................................................................... 13
Definitions of Potential................................................................................. 15
Market Characterization.............................................................................. 15
Baseline Projection...................................................................................... 17 Conservation Measure Analysis .................................................................... 17 Representative Conservation Measure Data Inputs ....................................... 19
Conservation Potential ................................................................................ 21
Data Development ................................................................................................ 21
Data Sources .............................................................................................. 21
AEG Data ................................................................................................... 23 Other Secondary Data and Reports ............................................................. 24
Data Application ................................................................................................... 24
Data Application for Market Characterization .............................................. 24 Data Application for Market Profiles ............................................................. 25
Data Application for Baseline Projection ...................................................... 25
Conservation Measure Data Application ...................................................... 31
Data Application for Technical Achievable Potential .................................... 32
3 MARKET CH ARACTE RIZATI ON AND M ARKET PROFILE S .......................................... 33
Energy Use Summary .............................................................................................. 33
Residential Sector .................................................................................................. 34
Commercial Sector ................................................................................................ 41
Industrial Sector ..................................................................................................... 48
4 BAS ELI NE PROJECTI ON ......................................................................................... 53
Residential Sector .................................................................................................. 53
Annual Use ................................................................................................. 53
Commercial Sector Baseline Projections .................................................................. 56
Annual Use ................................................................................................. 56
Industrial Sector Baseline Projections ....................................................................... 59
Annual Use ................................................................................................. 59
Summary of Baseline Projections across Sectors and States ....................................... 61
Annual Use ................................................................................................. 61
5 CONSE RV ATI ON POTE NTIAL.................................................................................. 62
Ov erall Summary of Energy Efficiency Potential........................................................ 62
Summary of Annual Energy Savings .............................................................. 62
Summary of Conservation Potential by Sector .......................................................... 66
Residential Conservation Potential .......................................................................... 67
Commercial Conservation Potential ........................................................................ 73
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 842 of 1105
Industrial Conservation Potential ............................................................................. 78
6 DEMAND RES PONSE POTE NTI AL .......................................................................... A-1
Market Characterization ....................................................................................... A-1
Market segmentation ................................................................................ A-1
Customer Counts by Segment.................................................................... A-2
Forecasts of Winter and Summer Peak Demand .......................................... A-3 System and Coincident Peak Forecasts by State ......................................... A-4 Equipment End Use Saturation ................................................................... A-6
DSM Program Options........................................................................................... A-8
Program Descriptions ................................................................................ A-8 Program Assumptions and Characteristics .................................................A-11
Other Cross-cutting Assumptions ...............................................................A-18
DR Potential and Cost Estimates ...........................................................................A-19
Integrated Potential Results ......................................................................A-19
Winter TOU Opt-in Scenario ......................................................................A-19 Cost Results .............................................................................................A-22 Winter TOU Opt-out Scenario ....................................................................A-23
Cost Results .............................................................................................A-26
Summer TOU Opt-in Scenario ....................................................................A-27
Cost Results .............................................................................................A-31 Summer TOU Opt-out Scenario..................................................................A-32
Cost Results .............................................................................................A-36
Stand-alone Potential Results ....................................................................A-37
Winter Results...........................................................................................A-37
Summer Results ........................................................................................A-40 Ancillary Serv ices .....................................................................................A-44
Winter Results...........................................................................................A-44
A MARKET PROFILES.................................................................................................. A-1
B MARKET ADOPTION (RAMP) RATES ........................................................................... B-1
C MEASURE DATA ..................................................................................................... C-1

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 843 of 1105
LIST OF FIGURES
Figure 2-1 LoadMAP Analysis Framework......................................................................... 14
Figure 2-2 Approach for Conservation Measure Assessment............................................. 18
Figure 3-1 Sector-Lev el Electricity Use in Base Year 2017, Washington ............................... 33
Figure 3-2 Sector-Lev el Electricity Use in Base Year 2017, Idaho ........................................ 34
Figure 3-3 Residential Electricity Use and Winter Peak Demand by End Use (2017),
Washington ................................................................................................... 35
Figure 3-4 Residential Electricity Use and Winter Peak Demand by End Use (2017), Idaho... 36
Figure 3-5 Residential Intensity by End Use and Segment (Annual kWh/HH, 2017),
Washington ................................................................................................... 37
Figure 3-6 Residential Intensity by End Use and Segment (Annual kWh/HH, 2017), Idaho .... 38
Figure 3-7 Commercial Electricity Use and Winter Peak Demand by End Use (2017),
Washington ................................................................................................... 43
Figure 3-8 Commercial Electricity Use and Winter Peak Demand by End Use (2017), Idaho
.................................................................................................................... 44
Figure 3-9 Commercial Electricity Usage by End Use Segment (GWh, 2017), Washington.... 45
Figure 3-10 Commercial Electricity Usage by End Use Segment (GWh, 2017), Idaho ............ 45
Figure 3-11 Industrial Electricity Use and Winter Peak Demand by End Use (2017), All
Industries, WA ................................................................................................ 48
Figure 3-12 Industrial Electricity Use and Winter Peak Demand by End Use (2017), All
Industries, ID .................................................................................................. 49
Figure 4-1 Residential Baseline Projection by End Use (GWh), Washington ......................... 54
Figure 4-2 Residential Baseline Projection by End Use – Annual Use per Household,
Washington ................................................................................................... 55
Figure 4-3 Residential Baseline Projection by End Use (GWh), Idaho.................................. 56
Figure 4-4 Residential Baseline Sales Projection by End Use – Annual Use per Household,
Idaho............................................................................................................ 56
Figure 4-5 Commercial Baseline Projection by End Use, Washington ................................. 58
Figure 4-6 Commercial Baseline Projection by End Use, Idaho .......................................... 58
Figure 4-7 Industrial Baseline Projection by End Use (GWh), Washington............................ 60
Figure 4-8 Industrial Baseline Projection by End Use (GWh), Idaho .................................... 60
Figure 4-9 Baseline Projection Summary (GWh), WA and ID Combined ............................. 61
Figure 5-1 Summary of EE Potential as % of Baseline Projection (Annual Energy),
Washington ................................................................................................... 64
Figure 5-2 Summary of EE Potential as % of Baseline Projection (Annual Energy), Idaho...... 64
Figure 5-3 Baseline Projection and EE Forecast Summary (Annual Energy, GWh),
Washington ................................................................................................... 65
Figure 5-4 Baseline Projection and EE Forecast Summary (Annual Energy, GWh), Idaho ..... 65
Figure 5-5 Technical Achievable Conservation Potential by Sector (Annual Energy, GWh)
.................................................................................................................... 66
Figure 5-6 Residential Conservation Savings as a % of the Baseline Projection (Annual
Energy), Washington ...................................................................................... 68
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 844 of 1105
Figure 5-7 Residential Conservation Savings as a % of the Baseline Projection (Annual
Energy), Idaho............................................................................................... 68
Figure 5-8 Residential Technical Achievable Sav ings Forecast (Cumulative GWh),
Washington ................................................................................................... 70
Figure 5-9 Residential Technical Achievable Savings Forecast (Cumulativ e GWh), Idaho ... 72
Figure 5-10 Commercial Conservation Savings (Energy), Washington ................................. 74
Figure 5-11 Commercial Conservation Savings (Energy), Idaho .......................................... 74
Figure 5-12 Commercial Technical Achiev able Sav ings Forecast (Cumulative GWh),
Washington ................................................................................................... 76
Figure 5-13 Commercial Technical Achievable Savings Forecast (Cumulative GWh), Idaho
.................................................................................................................... 78
Figure 5-14 Industrial Conservation Potential as a % of the Baseline Projection (Annual
Energy), Washington ...................................................................................... 79
Figure 5-15 Industrial Conservation Potential as a % of the Baseline Projection (Annual
Energy), Idaho............................................................................................... 80
Figure 5-16 Industrial Technical Achievable Sav ings Forecast (Cumulative GWh),
Washington ................................................................................................... 82
Figure 5-17 Industrial Technical Achievable Savings Forecast (Annual Energy, GWh), Idaho
.................................................................................................................... 83
Figure 6-1 Contribution to Estimated System Coincident Peak Forecast by State (Summer)
.................................................................................................................. A-5
Figure 6-2 Contribution to Estimated System Coincident Peak Forecast by State (Winter). A-6
Figure 6-3 Summary of Potential Analysis for Av ista (TOU Opt-In Winter Peak MW
@Generator) ..............................................................................................A-20
Figure 6-4 Summary of Winter Potential Analysis for Avista (TOU Opt-Out MW @Generator)
.................................................................................................................A-24
Figure 6-5 Summary of Summer Potential by Option (TOU Opt-In MW @Generator) .........A-28
Figure 6-6 Summary of Summer Potential – TOU Opt-Out (MW @Generator) ...................A-32
Figure 6-7 and Table A -1 show the winter demand savings from individual DR options for
selected years of the analysis. These sav ings represent stand-alone savings
from all av ailable DR options in Av ista’s Washington and Idaho serv ice
territories. ...................................................................................................A-37
Figure 6-8 Summary of Potential Analysis for Avista (Winter Peak MW @Generator).........A-38
Figure 6-9 Summary of Summer Potential by Option (MW @Generator) ..........................A-41

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 845 of 1105
LIST OF TABLES
Table 1-1 Explanation of Abbrev iations and Acronyms.................................................... 10
Table 2-1 Ov erview of Avista Analysis Segmentation Scheme.......................................... 16
Table 2-2 Example Equipment Measures for Central AC – Single-Family Home .................. 20
Table 2-3 Example Non-Equipment Measures – Single Family Home, Existing ..................... 20
Table 2-4 Number of Measures Evaluated ...................................................................... 20
Table 2-5 Data Applied for the Market Profiles ............................................................... 26
Table 2-6 Data Needs for the Baseline Projection and Potentials Estimation in LoadMAP... 27
Table 2-7 Residential Electric Equipment Standards ........................................................ 28
Table 2-8 Commercial Electric Equipment Standards ...................................................... 29
Table 2-9 Industrial Electric Equipment Standards ........................................................... 30
Table 2-10 Data Needs for the Measure Characteristics in LoadMAP ................................. 31
Ta ble 3-1 Avista Sector Control Totals (2017), Washington ............................................... 33
Table 3-2 Avista Sector Control Totals (2017), Idaho........................................................ 34
Table 3-3 Residential Sector Control Totals (2017), Washington ........................................ 34
Table 3-4 Residential Sector Control Totals (2017), Idaho................................................. 35
Table 3-5 Average Market Profile for the Residential Sector, 2017, Washington ................. 39
Table 3-6 Average Market Profile for the Residential Sector, 2017, Idaho ......................... 40
Table 3-7 Commercial Sector Control Totals (2017), Washington...................................... 41
Table 3-8 Commercial Sector Control Totals (2017), Idaho .............................................. 42
Table 3-9 Average Electric Market Profile for the Commercial Sector, 2017, Washington ... 46
Table 3-10 Average Electric Market Profile for the Commercial Sector, 2017, Idaho ........... 47
Table 3-11 Industrial Sector Control Totals (2017) .............................................................. 48
Table 3-12 Average Electric Market Profile for the Industrial Sector, 2017, Washington ........ 51
Table 3-13 Average Electric Market Profile for the Industrial Sector, 2017, Idaho................. 52
Table 4-1 Residential Baseline Sales Projection by End Use (GWh), Washington ................ 54
Table 4-2 Residential Baseline Sales Projection by End Use (GWh), Idaho ......................... 55
Table 4-3 Commercial Baseline Sales Projection by End Use (GWh), Washington .............. 57
Table 4-4 Commercial Baseline Sales Projection by End Use (GWh), Idaho ....................... 57
Table 4-5 Industrial Baseline Projection by End Use (GWh), Washington............................ 59
Table 4-6 Industrial Baseline Projection by End Use (GWh), Idaho .................................... 59
Table 4-7 Baseline Projection Summary (GWh), WA and ID Combined ............................. 61
Table 5-1 Summary of EE Potential (Annual Energy, GWh), Washington ............................ 63
Table 5-2 Summary of EE Potential (Annual Energy, GWh), Idaho..................................... 63
Table 5-3 Technical Achievable Conservation Potential by Sector (Annual Use), WA and
ID ................................................................................................................. 66
Table 5-4 Residential Conservation Potential (Annual Energy), Washington ...................... 67
Table 5-5 Residential Conservation Potential (Annual Energy), Idaho............................... 67
Table 5-6 Residential Top Measures in 2019 (Annual Energy, MWh), Washington ............... 69
Table 5-7 Residential Top Measures in 2019 (Annual Energy, MWh), Idaho ........................ 71
Table 5-8 Commercial Conservation Potential (Annual Energy), WA ................................ 73
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 846 of 1105
Table 5-9 Commercial Conservation Potential (Annual Energy), Idaho ............................ 73
Table 5-10 Commercial Top Measures in 2019 (Annual Energy, MWh), Washington ............. 75
Table 5-11 Commercial Top Measures in 2019 (Annual Energy, MWh), Idaho ...................... 77
Table 5-12 Industrial Conservation Potential (Annual Energy), WA ..................................... 78
Table 5-13 Industrial Conservation Potential (Annual Energy), Idaho ................................. 79
Table 5-14 Industrial Top Measures in 2019 (Annual Energy, GWh), Washington .................. 81
Table 5-15 Industrial Top Measures in 2019 (Annual Energy, GWh), Idaho ........................... 82
Table 6-1 Market Segmentation .................................................................................. A-2
Table 6-2 Baseline C&I Customer Forecast by State and Customer Class........................ A-2
Table 6-3 Baseline System Winter Peak Forecast (MW @Meter) ...................................... A-3
Table 6-4 Winter Load Factors and Baseline Coincident Peak Forecast by Segment (MW
@Meter) ...................................................................................................... A-4
Table 6-5 Summer Load Factors and Baseline Coincident Peak Forecast by Segment (MW
@Meter) ...................................................................................................... A-4
Table 6-6 2017 End Use Saturations by Customer Class, Washington............................... A-7
Table 6-7 2017 End Use Saturation by Customer Class, Idaho......................................... A-7
Table 6-8 Class 1 DSM Products Assessed in the Study ..................................................A-12
Table 6-9 DSM Steady-State Participation Rates (% of eligible customers) .....................A-13
Table 6-10 DSM Per Participant Impact Assumptions......................................................A-15
Table 6-11 DSM Program Operations Maintenance, and Equipment Costs (Washington) .A-16
Table 6-12 Marketing, Recruitment, Incentiv e, and Development Costs (Washington) .....A-17
Table 6-13 DSM Program Operations Maintenance, and Equipment Costs (Idaho) ..........A-17
Table 6-14 Marketing, Recruitment, Incentiv e, and Development Costs (Idaho) ..............A-18
Table 6-15 Achievable DR Potential by Option (TOU Opt-In Winter MW @Generator) .......A-20
Table 6-16 Achievable DR Potential by Option for Washington (TOU Opt-In Winter MW
@Generator) ..............................................................................................A-21
Table 6-17 Achievable DR Potential by Option for Idaho (TOU Opt-In Winter MW
@Generator) ..............................................................................................A-22
Table 6-18 DR Program Costs and Potential (TOU Opt-In Winter).....................................A-23
Table 6-19 Achievable DR Potential by Option – TOU Opt-Out (Winter MW @Generator) .A-24
Table 6-20 Achievable DR Potential by Option for Washington - TOU Opt-Out (MW
@Generator) ..............................................................................................A-25
Table 6-21 Achievable DR Potential by Option for Idaho – TOU Opt-Out (MW @Generator)
.................................................................................................................A-26
Table 6-22 DR Program Costs and Potential – TOU Opt Out Winter ..................................A-27
Table 6-23 Achievable DR Potential by Option TOU Opt-In (Summer MW @Generator) ....A-28
Table 6-24 Achievable DR Potential by Option for WashingtonTOU Opt-In (Summer MW
@Generator) ..............................................................................................A-29
Table 6-25 Achievable DR Potential by Option for Idaho TOU Opt-In (Summer MW
@Generator) ..............................................................................................A-30
Table 6-26 DR Program Costs and Potential – Summer TOU Opt-In ..................................A-31
Table 6-27 Achievable DR Potential by Option – TOU Opt-Out (Summer MW @Generator)A-34
Table 6-28 Achievable DR Potential by Option for Washington – TOU Opt-Out (Summer MW
@Generator) ..............................................................................................A-35
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 847 of 1105
Table 6-29 Achievable DR Potential by Option for Idaho – TOU Opt-Out (Summer MW
@Generator) ..............................................................................................A-35
Table 6-30 DR Program Costs and Potential – Summer TOU Opt-Out ...............................A-36
Figure 6-7 and Table 6-31 show the winter demand sav ings from indiv idual DR options for
selected years of the analysis. These sav ings represent stand-alone savings
from all av ailable DR options in Av ista’s Washington and Idaho serv ice
territories. ...................................................................................................A-37
Table 6-32 Achievable DR Potential by Option (Winter MW @Generator) ........................A-38
Table 6-33 Achievable DR Potential by Option for Washington (Winter MW @Generator).A-39
Table 6-34 Achievable DR Potential by Option for Idaho (Winter MW @Generator) .........A-40
Table 6-35 DR Program Costs and Potential (Winter).................. Error! Bookmark not defined.
Table 6-36 Achievable DR Potential by Option (Summer MW @Generator) .....................A-41
Table 6-37 Achievable DR Potential by Option for Washington (Summer MW @Generator)A-42
Table 6-38 Achievable DR Potential by Option for Idaho (Summer MW @Generator) .......A-43
Table 6-39 DR Program Costs and Potential – Summer ............... Error! Bookmark not defined.
Table A-1 Washington Residential Single Family Market Profile ....... Error! Bookmark not defined.
Table A-2 Washington Residential Multi Family Market Profile......... Error! Bookmark not defined.
Table A-3 Washington Residential Mobile Home Market Profile ...... Error! Bookmark not defined.
Table A-4 Washington Residential Low-Income Market Profile ........ Error! Bookmark not defined.
Table A-5 Washington Commercial Large Office Market Profile ..... Error! Bookmark not defined.
Table A-6 Washington Commercial Small Office Market Profile ...... Error! Bookmark not defined.
Table A-7 Washington Commercial Retail Market Profile................ Error! Bookmark not defined.
Table A-8 Washington Commercial Restaurant Market Profile ........ Error! Bookmark not defined.
Table A-9 Washington Commercial Grocery Market Profile ............ Error! Bookmark not defined.
Table A-10 Washington Commercial Health Market Profile ............ Error! Bookmark not defined.
Table A-11 Washington Commercial College Market Profile .......... Error! Bookmark not defined.
Table A-12 Washington Commercial School Market Profile ............ Error! Bookmark not defined.
Table A-13 Washington Commercial Lodging Market Profile .......... Error! Bookmark not defined.
Table A-14 Washington Commercial Warehouse Market Profile...... Error! Bookmark not defined.
Table A-15 Washington Commercial Miscellaneous Market Profile . Error! Bookmark not defined.
Table A-16 Washington Industrial Market Profile ............................ Error! Bookmark not defined.
Table A-17 Idaho Residential Single Family Market Profile .............. Error! Bookmark not defined.
Table A-18 Idaho Residential Multi Family Mark et Profile ................ Error! Bookmark not defined.
Table A-19 Idaho Residential Mobile Home Market Profile ............. Error! Bookmark not defined.
Table A-20 Idaho Residential Low-Income Market Profile ............... Error! Bookmark not defined.
Table A-21 Idaho Commercial Large Office Market Profile ............ Error! Bookmark not defined.
Table A-22 Idaho Commercial Small Office Market Profile ............. Error! Bookmark not defined.
Table A-23 Idaho Commercial Retail Market Profile....................... Error! Bookmark not defined.
Table A-24 Idaho Commercial Restaurant Market Profile ............... Error! Bookmark not defined.
Table A-25 Idaho Commercial Grocery Market Profile ................... Error! Bookmark not defined.
Table A-26 Idaho Commercial Health Market Profile ..................... Error! Bookmark not defined.
Table A-27 Idaho Commercial College Market Profile ................... Error! Bookmark not defined.
Table A-28 Idaho Commercial School Market Profile ..................... Error! Bookmark not defined.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 848 of 1105
Table A-29 Idaho Commercial Lodging Market Profile ................... Error! Bookmark not defined.
Table A-30 Idaho Commercial Warehouse Market Profile .............. Error! Bookmark not defined.
Table A-31 Idaho Commercial Miscellaneous Market Profile .......... Error! Bookmark not defined.
Table A-32 Idaho Industrial Market Profile..................................... Error! Bookmark not defined.
Table D-1 Impacts of HB 1444 on EE Potential .......................... Error! Bookmark not defined.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 849 of 1105

INTRODUCTION
Avista Corporation (Avista) engaged Applied Energy Group (AEG) to conduct a Conservation Potential Assessment (CPA). The CPA is a 20-year study, performed in accordance with Washington Initiative 937 (I-937), that provides data on conservation resources to support development of Avista’s 2022 Integrated Resource Plan (IRP). AEG first performed an electric CPA for Avista in 2013, and since then has performed both electric and gas CPAs for Avista’s planning cycles to date.
Notable udates to this study from prior CPAs include:
• The base-year for the analysis was brought forward from 2017 to 2019.
• For the residential sector, the study still incorporates Avista’s GenPOP residential saturation survey from 2012, which provides a more localized look at Avista’s customers than regional surveys. This provided the foundation for the base-year market characterization and energy market profiles. The Northwest Energy Efficiency Alliance’s (NEEA’s) 2016 Residential Building Stock Assessment (RBSA II) supplemented the GenPOP survey to account for trends in the intervening years.
• For the commercial sector, analysis was performed for the major building types in the service territory. Results from the 2019 Commercial Building Stock Assessment (CBSA), including hospital and university data, provided useful information for this characterization.
• This study also incorporated changes to the list of energy conservation measures, as a result of research by the Regional Technical Forum (RTF). In particular, LED lamps continue to drop in price and provide a significant opportunity for savings even under market transformation assumptions by the RTF.
• Measure characterizations which previously relied on data from the Northwest Power Council’s Sventh Power Plan is now updated to the 2021 Power Plan, including measure data, adoption rates, and updated measure applicability.
• The study incorporates updated forecasting assumptions that line up with the most recent Avista load forecast.
Enhancements retained from the 2019 CPA include:
• Analysis of economic potential was excluded from this study. Avista will screen for cost-effective opportunities directly within the IRP model. As such, economic potential and achievable potential have been replaced by a Technical Achievable Potential case.
• In addition to analyzing annual energy savings, the study also estimated the opportunity for reduction of summer and winter peak demand. This involved a full characterization by sector, segment and end use of peak demand in the base year.
• Finally, this year’s study included an update to the 2019 assessment of demand-response potential, including analysis of residential programs as well as commercial and industrial (C&I), and options for both summer and winter demand reduction.
Compared to the 2019 Study, 10-year technical achievable potential has increased from 110.1 aMW to 150.3 aMW. This is a net effect of changes in the measure list, market transformation, and baseline growth.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 850 of 1105
Abbreviations and Acronyms
Table 1-1 provides a list of abbreviations and acronyms used in this report, along with an explanation.
Table 1-1 Explanation of Abbreviations and Acronyms
Acronym Explanation
ACS American Community Survey
AEO Annual Energy Outlook forecast developed by EIA
AHAM Association of Home Appliance Manufacturers
AMI Advanced Metering Infrastructure
AMR Automated Meter Reading
Auto-DR Automated Demand Response
B/C Ratio Benefit to Cost Ratio
BEST AEG’s Building Energy Simulation Tool
C&I Commercial and Industrial
CAC Central Air Conditioning
CFL Compact fluorescent lamp
CPP Critical Peak Pricing
C&I Commercial and Industrial
DHW Domestic Hot Water
DLC Direct Load Control
DR Demand Response
DSM Demand Side Management
EE Energy Efficiency
EIA Energy Information Administration
EUL Estimated Useful Life
EUI Energy Usage Intensity
FERC Federal Energy Regulatory Commission
HH Household
HID High intensity discharge lamps
HVAC Heating Ventilation and Air Conditioning
ICAP Installed Capacity
IOU Investor Owned Utility
LED Light emitting diode lamp
LoadMAP AEG’s Load Management Analysis and Planning™ tool
LCOE Levelized cost of energy
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 851 of 1105
Acronym Explanation
MW Megawatt
NPV Net Present Value
O&M Operations and Maintenance
TRC Total Resource Cost test
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Schedule 1a, Page 853 of 1105

ANALYSIS APPROACH AND DATA DEVELOPMENT
This section describes the analysis approach taken for the study and the data sources used to develop the potential estimates.
Overview of Analysis Approach
To perform the potential analysis, AEG used a bottom-up approach following the major steps listed below. We describe these analysis steps in more detail throughout the remainder of this chapter.
1. Perform a market characterization to describe sector-level electricity use for the residential, commercial, and industrial sectors for the base year, 2019.
2. Develop a baseline projection of energy consumption and peak demand by sector, segment, and end use for 2019 through 2045.
3. Define and characterize several hundred conservation measures to be applied to all sectors, segments, and end uses.
4. Estimate technical and Technical Achievable Potential at the measure level in terms of energy and peak demand impacts from conservation measures for 2019-2045.
LoadMAP Model
AEG used its Load Management Analysis and Planning tool (LoadMAP™) version 5.0 to develop both the baseline projection and the estimates of potential. AEG developed LoadMAP in 2007 and has enhanced it over time, using it for the EPRI National Potential Study and numerous utility-specific forecasting and potential studies since that time. Built in Excel, the LoadMAP framework (see Figure 2-1) is both accessible and transparent and has the following key features.
• Embodies the basic principles of rigorous end-use models (such as EPRI’s REEPS and COMMEND) but in a more simplified, accessible form.
• Includes stock-accounting algorithms that treat older, less efficient appliance/equipment stock separately from newer, more efficient equipment. Equipment is replaced according to the measure life and appliance vintage distributions defined by the user.
• Balances the competing needs of simplicity and robustness by incorporating important modeling details related to equipment saturations, efficiencies, vintage, and the like, where market data are available, and treats end uses separately to account for varying importance and availability of data resources.
• Isolates new construction from existing equipment and buildings and treats purchase decisions for new construction and existing buildings separately.
• Uses a simple logic for appliance and equipment decisions. Other models available for this purpose embody complex decision choice algorithms or diffusion assumptions, and the model parameters tend to be difficult to estimate or observe and sometimes produce anomalous results that require calibration or even overriding. The LoadMAP approach allows the user to drive the appliance and equipment choices year by year directly in the model. This flexible approach allows users to import
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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the results from diffusion models or to input individual assumptions. The framework also facilitates sensitivity analysis.
• Includes appliance and equipment models customized by end use. For example, the logic for lighting is distinct from refrigerators and freezers.
• Can accommodate various levels of segmentation. Analysis can be performed at the sector level (e.g., total residential) or for customized segments within sectors (e.g., housing type or income level).
• Can incorporate conservation measures, demand-response options, combined heat and power (CHP) and distributed generation options and fuel switching.
Consistent with the segmentation scheme and the market profiles we describe below, the LoadMAP model provides projections of baseline energy use by sector, segment, end use, and technology for existing and new buildings. It also provides forecasts of total energy use and energy-efficiency savings associated with the various types of potential.1
Figure 2-1 LoadMAP Analysis Framework

1 The model computes energy and peak-demand forecasts for each type of potential for each end use as an intermediate calculation. Annual-energy and peak-demand savings are calculated as the difference between the value in the baseline projection and the value in the potential forecast (e.g., the technical potential forecast).
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 855 of 1105
Definitions of Potential
In this study, the conservation potential estimates represent gross savings developed for two levels of potential: technical potential and Technical Achievable Potential. These levels are described below.
• Te chnical Potential is defined as the theoretical upper limit of conservation potential. It assumes that customers adopt all feasible measures regardless of their cost. At the time of existing equipment failure, customers replace their equipment with the efficient option available. In new construction, customers and developers also choose the most efficient equipment option.
o In new construction, customers and developers also choose the efficient equipment option relative to applicable codes and standards. Non-equipment measures which may be realistically installed apart from equipment replacements are implemented according to ramp rates developed by the NWPCC for its 2021 Power Plan, applied to 100% of the applicable market. This case is a theoretical construct and is provided primarily for planning and informational purposes.
• Te chnical Achievable Potential re fines Technical Potential by applying customer participation rates that account for market barriers, customer awareness and attitudes, program maturity, and other factors that may affect market penetration of DSM measures. We used achievability assumptions from the Council’s 2021 Power Plan, adjusted for Avista’s recent program accomplishments, as the customer adoption rates for this study. For the technical achievable case, ramp rates are applied to bewteen 85%-100% of the applicable market, per Council methodology. This achievability factor represents potential which can reasonably be acquired by all mechanisms available, regardless of how conservation is achieved. Thus, the market applicability assumptions utilized in this study include savings outside of utility programs.2
o Note that in the 2019 CPA, ramp rates used Sventh Plan methdology, which assumed a fixed 85% achievability for all measures. In the 2021 Power Plan, some measures have this limit increased.
o Details regarding the market adoption factors appear in Appendix B.
Market Characterization
The first step in the analysis approach is market characterization. In order to estimate the savings potential from energy-efficient measures, it is necessary to understand how much energy is used today and what equipment is currently being used. This characterization begins with a segmentation of Avista’s electricity footprint to quantify energy use by sector, segment, end-use application, and the current set of technologies used. We rely primarily on information from Avista, NEEA, and secondary sources as necessary.
Segmentation for Modeling Purposes
The market assessment first defined the market segments (building types, end uses, and other dimensions) that are relevant in the Avista service territory. The segmentation scheme for this project is presented in Table 2-1.

2 Council’s 7th Power Plan applicability assumptions reference an “Achievable Savings” report published August 1, 2007. http://www.nwcouncil.org/reports/2007/2007-13/
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 856 of 1105
Table 2-1 Overview of Avista Analysis Segmentation Scheme
Dimension Segmentation Variable Description
1 Sector Residential, commercial, industrial
2 Segment
Residential: single family, multifamily, manufactured home, low
income
Commercial: small office, large office, restaurant, retail, grocery,
college, school, health, lodging, warehouse, and miscellaneous
Industrial: total
3 Vintage Existing and new construction
4 End uses Cooling, lighting, water heat, motors, etc. (as appropriate by
sector)
5 Appliances/end uses and
technologies
Technologies such as lamp type, air conditioning equipment,
motors by application, etc.
6 Equipment efficiency levels
for new purchases
Baseline and higher-efficiency options as appropriate for each
technology

With the segmentation scheme defined, we then performed a high-level market characterization of electricity sales in the base year to allocate sales to each customer segment. We used Avista data and secondary sources to allocate energy use and customers to the various sectors and segments such that the total customer count, energy consumption, and peak demand matched the Avista system totals from 2017 billing data. This information provided control totals at a sector level for calibrating the LoadMAP model to known data for the base-year.
Market Profiles
The next step was to develop market profiles for each sector, customer segment, end use, and technology. A market profile includes the following elements:
• Ma rket size is a representation of the number of customers in the segment. For the residential sector, it is number of households. In the commercial sector, it is floor space measured in square feet. For the industrial sector, it is overall electricity use.
• S a turations define the fraction of homes or square feet with the various technologies. (e.g., homes with electric space heating).
• U E C (unit energy consumption) or EUI (energy-use index) describes the amount of energy consumed in 2019 by a specific technology in buildings that have the technology. For electricity, UECs are expressed in kWh/household for the residential sector, and EUIs are expressed in kWh/square foot for the commercial sector.
• Annual E nergy Intensity for the residential sector represents the average energy use for the technology across all homes in 2019. It is computed as the product of the saturation and the UEC and is defined as kWh/household for electricity. For the commercial sector, intensity, computed as the product of the saturation and the EUI, represents the average use for the technology across all floor space in 2019.
• Annual U sage is the annual energy use by an end-use technology in the segment. It is the product of the market size and intensity and is quantified in GWh.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 857 of 1105
• Pe ak De mand for each technology, summer peak and winter peak are calculated using peak fractions of annual energy use from AEG’s EnergyShape library and Avista system peak data.
o The market characterization results, and the market profiles are presented in Chapter 3.
Baseline Projection
The next step was to develop the baseline projection of annual electricity use and summer peak demand for 2019 through 2045 by customer segment and end use without new utility programs. The end-use projection includes the impacts of relatively certain codes and standards which will unfold over the study timeframe. All such mandates that were defined as of July 2020 are included in the baseline. The baseline projection is the foundation for the analysis of savings from future conservation efforts as well as the metric against which potential savings are measured.
Inputs to the baseline projection include:
• Current economic growth forecasts (i.e., customer growth, income growth)
• Electricity price forecasts
• Trends in fuel shares and equipment saturations
• Existing and approved changes to building codes and equipment standards
• Avista’s internally developed sector-level projections for electricity sales
We also developed a baseline projection for summer and winter peak by applying the peak fractions from the energy market profiles to the annual energy forecast in each year.
We present the baseline-projection results for the system as a whole and for each sector in Chapter 4.
Washington HB 1444
While the 2019 CPA was completed before the impacts of HB-1444 could be incorporated, requiring a separate analysis to estimate that impact, this study’s foundational setup included assumptions of HB-1444s impact on the available market for energy efficiency measures in Washington.
Conservation Measure Analysis
This section describes the framework used to assess the savings, costs, and other attributes of conservation measures. These characteristics form the basis for measure-level cost-effectiveness analyses as well as for determining measure-level savings. For all measures, AEG assembled information to reflect equipment performance, incremental costs, and equipment lifetimes. We used this information, along with the Seventh Plan’s updated ramp rates to identify technical achievable measure potential.
Conservation Measures
Figure 2-2 outlines the framework for conservation measure analysis. The framework for assessing savings, costs, and other attributes of conservation measures involves identifying the list of measures to include in the analysis, determining their applicability to each market sector and segment, fully characterizing each measure, and calculating the levelized cost of energy ($/MWh). Potential measures include the replacement of a unit that has failed or is at the end of its useful life with an efficient unit, retrofit or early replacement of equipment, improvements to the building envelope, the application of controls to optimize energy use, and other actions resulting in improved energy efficiency.
We compiled a robust list of conservation measures for each customer sector, drawing upon Avista’s measure database, the Regional Technical Forum (RTF), and the Seventh Plan deemed measures database,
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 858 of 1105
as well as a variety of secondary sources. This universal list of conservation measures covers all major types of end-use equipment, as well as devices and actions to reduce energy consumption.
Since an economic screen was not performed in this Study, we have instead calculated the levelized cost of energy (LCOE) for each measure evaluated. This value, expressed in dollars per first-year megawatt hour (MWh) saved, can be used by Avista’s IRP model to evaluate cost effectiveness. To calculate a measure’s LCOE, first-year measure costs, annual non-energy benefits, and annual operations and maintenance (O&M) costs are levelized over a measure’s lifetime, then divided by the first-year savings in MWh. Note that while non-energy benefits are typically included in the numerator of a traditional Total Resource Cost (TRC) economic screen, the LCOE benefits have not been monetized. Therefore, these benefits are instead subtracted from the costs portion of the test. These benefits are not included in the Utility Cost Test (UCT) used in Idaho.

Figure 2-2 Approach for Conservation Measure Assessment

The selected measures are categorized into two types according to the LoadMAP taxonomy: equipment measures and non-equipment measures.
• E q uipment measures are efficient energy-consuming pieces of equipment that save energy by providing the same service with a lower energy requirement than a standard unit. An example is an ENERGY STAR refrigerator that replaces a standard efficiency refrigerator. For equipment measures, many efficiency levels may be available for a given technology, ranging from the baseline unit (often determined by code or standard) up to the most efficient product commercially available. For instance, in the case of central air conditioners, this list begins with the current federal standard SEER 13 unit and spans a broad spectrum up to a maximum efficiency of a SEER 21 unit. The Seventh Plan’s “Lost Opportunity” ramp rates are primarily applied to equipment measures.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 859 of 1105
• N on-equipment measure s save energy by reducing the need for delivered energy, but do not involve replacement or purchase of major end-use equipment (such as a refrigerator or air conditioner). An example would be a programmable thermostat that is pre-set to run heating and cooling systems only when people are home. Non-equipment measures can apply to more than one end use. For instance, addition of wall insulation will affect the energy use of both space heating and cooling. The Seventh Plan’s “Retrofit” ramp rates are primarily applied to no-equipment measures. Non-equipment measures typically fall into one of the following categories:
o Building shell (windows, insulation, roofing material)
o Equipment controls (thermostat, compressor staging and controls)
o Equipment maintenance (cleaning filters, changing setpoints)
o Whole-building design (building orientation, advanced new construction designs)
o Lighting retrofits (assumed to be implemented alongside new LEDs at the equipment’s normal end of life)
o Displacement measures (ceiling fan to reduce use of central air conditioners)
o Commissioning and retrocommissioning (initial or ongoing monitoring of building energy systems to optimize energy use)
We developed a preliminary list of conservation measures, which was distributed to the Avista project team for review. The list was finalized after incorporating comments and is presented in the appendix to this volume.
Once we assembled the list of conservation measures, the project team characterized measure savings, incremental cost, service life, and other performance factors, drawing upon data from the Avista measure database, the Seventh Power Plan, the RTF deemed measure workbooks, simulation modeling, and other well-vetted sources as required.
Representative Conservation Measure Data Inputs
To provide an example of the conservation measure data, Table 2-2 and Table 2-3 present examples of the detailed data inputs behind both equipment and non-equipment measures, respectively, for the case of residential CAC in single-family homes. Table 2-2 displays the various efficiency levels available as equipment measures, as well as the corresponding useful life, energy usage, and cost estimates. The columns labeled “On Market” and “Off Market” reflect equipment availability due to codes and standards or the entry of new products to the market. Note that in this example no standards come into play and therefore all options are available throughout the forecast.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 860 of 1105
Table 2-2 Example Equipment Measures for Central AC – Single-Family Home
Efficiency Level Useful Life (yrs) Equipment Energy Usage (kWh/yr)
On Off
Cost Market Market
SEER 13.0 10 to 20 $2,097 1,383 2019 n/a
SEER 14.0 10 to 20 $2,505 1,284 2019 n/a
SEER 15.0 10 to 20 $2,913 1,199 2019 n/a
SEER 16.0 10 to 20 $3,321 1,124 2019 n/a
SEER 18.0 10 to 20 $4,140 999 2019 n/a
SEER 20.0 10 to 20 $4,955 899 2019 n/a

Table 2-3 lists some of the non-equipment measures applicable to a CAC in an existing single family home. LCOE values for all measures are evaluated based on the lifetime costs of the measure divided by the first-year savings. The total costs and savings are calculated for each year of the study and depend on the base year saturation of the measure, the applicability3 of the measure, and the savings as a percentage of the relevant energy end uses.
Table 2-3 Example Non-Equipment Measures – Single Family Home, Existing
End Use Measure Saturation
in 2019 Applicability Lifetime
(yrs)
Measure
Installed Cost
Energy
Savings (%)
Cooling Insulation - Ceiling Installation 0% 10% 45 $2,084 21.8%
Cooling Insulation - Wall Cavity Installation 0% 10% 45 $4,374 3.5%
Cooling Windows - High Efficiency/ENERGY STAR 0% 95% 45 $4,421 7.1%
Cooling Thermostat – Connected 14% 70% 5 $265.00 6.0%

Table 2-4 summarizes the number of measures evaluated for each segment within each sector.
Table 2-4 Number of Measures Evaluated
Sector Total Measures Permutations w/ Permutations w/
Total Measures Evaluated 329 658 3,786

3 The applicability factors take into account whether the measure is applicable to a particular building type and whether it is feasible to install the measure. For instance, attic fans are not applicable to homes where there is insufficient space in the attic or there is no attic at all.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 861 of 1105
Conservation Potential
The approach we used for this study to calculate the conservation potential adheres to the approaches and conventions outlined in the National Action Plan for Energy-Efficiency (NAPEE) Guide for Conducting Potential Studies (November 2007).4 The NAPEE Guide represents the most credible and comprehensive industry practice for specifying conservation potential. As described in Chapter 2, two types of potential were developed as part of this effort: Technical Potential and Technical Achievable Potential.
• Te chnical potential is a theoretical construct that assumes the highest efficiency measures that are technically feasible to install are adopted by customers, regardless of cost or customer preferences. Thus, determining the technical potential is relatively straightforward. LoadMAP “chooses” the efficient equipment options for each technology at the time of equipment replacement. In addition, it installs all relevant non-equipment measures for each technology to calculate savings. LoadMAP applies the savings due to the non-equipment measures one-by-one to avoid double counting of savings. The measures are evaluated in order of their LCOE ratio, with the measure with the lowest LCOE values (most likely to be cost effective) applied first. Each time a measure is applied, the baseline energy use for the end use is reduced and the percentage savings for the next measure is applied to the revised (lower) usage.
• Te chnical Achievable Potential refines Technical Potential by applying market adoption rates for each measure that estimate the percentage of customers who would be likely to select each measure, given consumer preferences (partially a function of incentive levels), retail energy rates, imperfect information, and real market barriers and conditions. These barriers tend to vary, depending on the customer sector, local energy market conditions, and other, hard-to-quantify factors. In addition to utility-sponsored programs, alternative acquisition methods, such as improved codes and standards and market transformation, can be used to capture portions of these resources, and are included within the Technical Achievable Potential, per 2021 Power Plan methodology.
The calculation of Technical Potential is a straightforward algorithm. To develop estimates for Technical Achievable Potential, we develop market adoption rates for each measure that specify the percentage of customers that will select the highest–efficiency economic option. With the beginning of a new power plan, technical achievable potential aligns with ramp assignments from the 2021 Power Plan. Over time, measure adoption increases from the starting point up to 85% or more, to model increasing market acceptance and program improvements. For measures within the 2021 Power Plan, the Council’s prescribed ramp rates were used. For measures outside the 2021 Plan, AEG assigned ramp rates comparable to similar measures within the 2021 Plan. The market adoption rates for each measure appear in Appendix B.
Results of all the potentials analysis are presented in Chapter 5.
Data Development
This section details the data sources used in this study, followed by a discussion of how these sources were applied. In general, data sources were applied in the following order: Avista data, Northwest data, and well-vetted national or other regional secondary sources.
Data Sources
The data sources are organized into the following categories:
4 National Action Plan for Energy Efficiency (2007). National Action Plan for Energy Efficiency Vision for 2025: Developing a Framework for Change. www.epa.gov/eeactionplan.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 862 of 1105
• Avista data
• Northwest Energy Efficiency Alliance data
• Northwest Power and Conservation Council data
• AEG’s databases and analysis tools
• Other secondary data and reports
Avista Data
Our highest priority data sources for this study were those that were specific to Avista.
• Avista customer data: Avista provided billing data for development of customer counts and energy use for each sector. We also used the results of the Avista GenPOP survey, a residential saturation survey.
• Load forecasts: Avista provided an economic growth forecast by sector; electric load forecast; peak-demand forecasts at the sector level; and retail electricity price history and forecasts.
• E conomic information: Avista Power provided a discount rate and line loss factor. Avoided costs were not provided due to the economic screen being moved to the IRP model.
• Avista program d ata: Avista provided information about past and current programs, including program descriptions, goals, and achievements to date.
Northwest Energy Efficiency Alliance Data
The Northwest Energy Efficiency Alliance conducts research on an ongoing basis for the Northwest region. The following studies were particularly useful for this study:
• N orthwest E nergy E fficiency Alliance, Residential Building S tock Assessment II , Single-Family Homes Report 2016-2017, https://neea.org/img/uploads/Residential-Building-Stock-Assessment-II-Single-Family-Homes-Report-2016-2017.pdf
• N orthwest E nergy E fficiency Alliance, R esidential Building S tock Assessment II, Manufactured Homes Report 2016-2017, https://neea.org/img/uploads/Residential-Building-Stock-Assessment-II-Manufactured-Homes-Report-2016-2017.pdf
• N orthwest E nergy E fficiency Alliance, R esidential Building S tock Assessment II, Multifamily Buildings Report 2016-2017, https://neea.org/img/documents/Residential-Building-Stock-Assessment-II-Multifamily-Homes-Report-2016-2017.pdf
• N orthwest E nergy E fficiency Alliance, 2019 Commercial Building Stock Assessment, May 21, 2020 https://neea.org/resources/cbsa-4-2019-final-report
• N orthwest E ne rgy E fficiency Alliance, 2014 Ind ustrial Fa cilities S ite Assessment, December 29, 2014, http://neea.org/docs/default-source/reports/2014-industrial-facilities-stock-assessment-final-report.pdf?sfvrsn=6
Northwest Power and Conservation Council Data
Several sources of data were used to characterize the conservation measures. We used the following regional data sources and supplemented with AEG’s data sources to fill in any gaps.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 863 of 1105
• R egional Technical Forum Deemed Measures. The NWPCC Regional Technical Forum maintains databases of deemed measure savings data, available at http://www.nwcouncil.org/energy/rtf/measures/Default.asp .
• N orthwest Power a nd Conservation Council 2021 Power Pla n Conservation Supply Cur ve Workbooks. To develop its 2021 Power Plan, the Council used workbooks with detailed information about measures, available at https://nwcouncil.box.com/s/u0dgjxkoxoj2tttym81uka3wrjcy6bo6
• N orthwest Power and Conservation Council, MC and Loadshape File, September 29, 2016. The Council’s load shape library was utilized to convert CPA results into hourly conservation impacts for use in Avista’s IRP process. Generalized Least Square (GLS) versions of these load shapes are available at https://nwcouncil.app.box.com/s/gacr21z8i89hh8ppk11rdzgm6fz4xlz3
AEG Data
AEG maintains several databases and modeling tools that we use for forecasting and potential studies. Relevant data from these tools has been incorporated into the analysis and deliverables for this study.
• AE G E nergy Ma rket Profiles: For more than 10 years, AEG staff has maintained profiles of end-use consumption for the residential, commercial, and industrial sectors. These profiles include market size, fuel shares, unit consumption estimates, and annual energy use by fuel (electricity and natural gas), customer segment and end use for 10 regions in the U.S. The Energy Information Administration surveys (RECS, CBECS and MECS) as well as state-level statistics and local customer research provide the foundation for these regional profiles.
• Building E nergy S imulation Tool (BEST). AEG’s BEST is a derivative of the DOE 2.2 building simulation model, used to estimate base-year UECs and EUIs, as well as measure savings for the HVAC-related measures.
• AE G’s EnergyShape™: AEG’s load shape database was used in addition to the Council’s load shape database for comparative purposes. This database of load shapes includes the following:
o Residential – electric load shapes for ten regions, three housing types, 13 end uses
o Commercial – electric load shapes for nine regions, 54 building types, ten end uses
o Industrial – electric load shapes, whole facility only, 19 2-digit SIC codes, as well as various 3-digit and 4-digit SIC codes
• AE G’s Database of Energy E fficiency Measures (DEEM): AEG maintains an extensive database of measure data for our studies. Our database draws upon reliable sources including the California Database for Energy Efficient Resources (DEER), the EIA Technology Forecast Updates – Residential and Commercial Building Technologies – Reference Case,RS Means cost data, and Grainger Catalog Cost data
• R e cent studies. AEG has conducted numerous studies of EE potential in the last five years. We checked our input assumptions and analysis results against the results from these other studies, which include Tacoma Power, Idaho Power, PacifiCorp, Ameren Missouri, Vectren Energy, Indianapolis Power & Light, Tennessee Valley Authority, Ameren Missouri, Ameren Illinois, and Seattle City Light. In
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 864 of 1105
addition, we used the information about impacts of building codes and appliance standards from recent reports for the Edison Electric Institute5.
Other Secondary Data and Reports
Finally, a variety of secondary data sources and reports were used for this study. The main sources are identified below.
• Annual E nergy Outlook. The Annual Energy Outlook (AEO), conducted each year by the U.S. Energy Information Administration (EIA), presents yearly projections and analysis of energy topics. For this study, we used data from the 2019 AEO.
• Local Weather Data: Weather from NOAA’s National Climatic Data Center for Spokane, WA was used as the basis for building simulations.
• E PRI End-Use Models (REEPS and COMMEND). These models provide the elasticities we apply to electricity prices, household income, home size and heating and cooling.
• Da tabase for E nergy E fficient R esources (DEER). The California Energy Commission and California Public Utilities Commission (CPUC) sponsor this database, which is designed to provide well-documented estimates of energy and peak demand savings values, measure costs, and effective useful life (EUL) for the state of California. We used the DEER database to cross check the measure savings we developed using BEST and DEEM.
• Other relevant regional sources: These include reports from the Consortium for Energy Efficiency (CEE), the Environmental Protection Agency (EPA), and the American Council for an Energy-Efficient Economy (ACEEE).
Data Application
We now discuss how the data sources described above were used for each step of the study.
Data Application for Market Characterization
To construct the high-level market characterization of electricity use and households/floor space for the residential, commercial and industrial sectors, we used Avista billing data and customer surveys to estimate energy use.
• For the residential sector, Avista estimated the numbers of customers and the average energy use per customer for each of the three segments, based on its GenPOP survey, matched to billing data for surveyed customers. AEG compared the resulting segmentation with data from the American Community Survey (ACS) regarding housing types and income and found that the Avista segmentation corresponded well with the ACS data. (See Chapter 3 for additional details.)
• To segment the commercial and industrial segments, we relied upon the allocation from the previous energy efficiency potential study. For the previous study, customers and sales were allocated to
o 5 AEG staff has prepared three white papers on the topic of factors that affect U.S. electricity
consumption, including appliance standards and building codes. Links to all three white papers are provided:
http://www.edisonfoundation.net/IEE/Documents/IEE_RohmundApplianceStandardsEfficiencyCodes1209.pdf
o http://www.edisonfoundation.net/iee/Documents/IEE_CodesandStandardsAssessment_2010-2025_UPDATE.pdf.
o http://www.edisonfoundation.net/iee/Documents/IEE_FactorsAffectingUSElecConsumption_Final.pdf

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 865 of 1105
building type based on SIC codes, with some adjustments between the commercial and industrial sectors to better group energy use by facility type and predominate end uses. (See Chapter 3 for additional details.)
Data Application for Market Profiles
The specific data elements for the market profiles, together with the key data sources, are shown in Table 2-5. To develop the market profiles for each segment, we did the following:
1. Developed control totals for each segment. These include market size, segment-level annual electricity use, and annual intensity.
2. Used the Avista GenPOP Survey, NEEA’s RBSA, NEEA’s CBSA, NEEA’s IFSA, and AEG’s Energy Market Profiles database to develop existing appliance saturations, appliance and equipment characteristics, and building characteristics.
3. Ensured calibration to control totals for annual electricity sales in each sector and segment.
4. Compared and cross-checked with other recent AEG studies.
5. Worked with Avista staff to vet the data against their knowledge and experience.

Data Application for Baseline Projection
Table 2-5 summarizes the LoadMAP model inputs required for the baseline projection. These inputs are required for each segment within each sector, as well as for new construction and existing dwellings/buildings.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 866 of 1105
Table 2-5 Data Applied for the Market Profiles
Model Inputs Description Key Sources
Market size Base-year residential dwellings, commercial
floor space, and industrial employment
Avista billing data
Avista GenPOP Survey
NEEA RBSA and CBSA
AEO 2019
Annual intensity
Residential: Annual use per household
Commercial: Annual use per square foot
Industrial: Annual use per employee
Avista billing data
AEG’s Energy Market Profiles
NEEA RBSA and CBSA
AEO 2019
Other recent studies
Appliance/equipment
saturations
Fraction of dwellings with an
appliance/technology
Percentage of C&I floor space/employment
with equipment/technology
Avista GenPOP Survey
NEEA RBSA and CBSA
AEG’s Energy Market Profiles
UEC/EUI for each end-
use technology
UEC: Annual electricity use in homes and
buildings that have the technology
EUI: Annual electricity use per square
foot/employee for a technology in floor space
that has the technology
NWPCC RTF and Seventh Plan and
RTF
HVAC uses: BEST simulations using
prototypes developed for Idaho
Engineering analysis
DEEM
Recent AEG studies
Appliance/equipment
age distribution Age distribution for each technology
RTF and NWPCC Seventh Plan data
NEEA regional survey data
Utility saturation surveys
Recent AEG studies
Efficiency options for
each technology
List of available efficiency options and annual
energy use for each technology
AEG DEEM
AEO 2019
DEER
RTF and NWPCC 2021 Plan data
Previous studies
Peak factors Share of technology energy use that occurs
during the peak hour EnergyShape database

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 867 of 1105
Table 2-6 Data Needs for the Baseline Projection and Potentials Estimation in LoadMAP
Model Inputs Description Key Sources
Customer growth forecasts Forecasts of new construction in
residential and C&I sectors
Avista load forecast
AEO 2019 economic growth forecast
Equipment purchase shares
for baseline projection
For each equipment/technology, purchase
shares for each efficiency level; specified
separately for existing equipment
replacement and new construction
Shipments data from AEO and
ENERGY STAR
AEO 2019 regional forecast
assumptions6
Appliance/efficiency standards
analysis
Avista program results and
evaluation reports
Utilization model
parameters
Price elasticities, elasticities for other
variables (income, weather)
EPRI’s REEPS and COMMEND
models
AEO 2019

In addition, we implemented assumptions for known future equipment standards as of September 2018, as shown in Table 2-6, Table 2-7 and Table 2-8. The assumptions tables here extend through 2025, after which all standards are assumed to hold steady.

6 We developed baseline purchase decisions using the Energy Information Agency’s Annual Energy Outlook report (2016), which utilizes the National Energy Modeling System (NEMS) to produce a self-consistent supply and demand economic model. We calibrated equipment purchase options to match manufacturer shipment data for recent years and then held values constant for the study period. This removes any effects of naturally occurring conservation or effects of future EE programs that may be embedded in the AEO forecasts.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 868 of 1105
Table 2-7 Residential Electric Equipment Standards7
End Use Technology 2019 2020 2021 2022 2023 2024 2025
Cooling Central AC SEER 13.0
Room AC EER 10.8
Air-Source Heat Pump SEER 13.0 / HSPF 8.2 SEER 14.0 / HSPF 9.0 Heating
EF 0.95 (<=55 gallons)
EF 2.0 (Heat Pump Water Heater)
Lighting General Service Advanced Incandescent
(~20 lumens/watt) Advanced Incandescent (~45 lumens/watt)

25% more efficient than the 1997 Final Rule (62 FR 23102) Freezer
Clothes Dryer 3.73 Combined EF

7 The assumptions tables here extend through 2025, after which all standards are assumed to hold steady.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 869 of 1105
Table 2-8 Commercial Electric Equipment Standards8

Cooling
Cooling/ Heating
Heat Pump
Lighting
General Service
Refrigeration

8 The assumptions tables here extend through 2025, after which all standards are assumed to hold steady.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 870 of 1105
Table 2-9 Industrial Electric Equipment Standards9

Cooling
Cooling/ Heating
Heat Pump
Lighting
General Service

9 The assumptions tables here extend through 2025, after which all standards are assumed to hold steady.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 871 of 1105
Conservation Measure Data Application
Table 2-9 details the energy-efficiency data inputs to the LoadMAP model. It describes each input and identifies the key sources used in the Avista analysis.
Table 2-10 Data Needs for the Measure Characteristics in LoadMAP
Model Inputs Description Key Sources
Energy Impacts
The annual reduction in consumption attributable to
each specific measure. Savings were developed as a
percentage of the energy end use that the measure
affects.
Avista measure data
NWPCC workbooks, RTF
NWPCC Seventh Plan
conservation workbooks
BEST
AEG DEEM
AEO 2019
DEER
Other secondary sources
Peak Demand Impacts
Savings during the peak demand periods are specified
for each electric measure. These impacts relate to the
energy savings and depend on the extent to which
each measure is coincident with the system peak.
Avista measure data
BEST
AEG DEEM
EnergyShape
Costs
Equipment Measures: Includes the full cost of
purchasing and installing the equipment on a per-household, per-square-foot, per employee or per
service point basis for the residential, commercial,
and industrial sectors, respectively.
Non-equipment measures: Existing buildings – full
installed cost. New Construction - the costs may be
either the full cost of the measure, or as appropriate, it may be the incremental cost of upgrading from a
standard level to a higher efficiency level.
Avista measure data
NWPCC workbooks, RTF
NWPCC 2021 Plan
conservation workbooks
AEG DEEM
AEO 2019
DEER
RS Means
Other secondary sources
Measure Lifetimes
Estimates derived from the technical data and
secondary data sources that support the measure
demand and energy savings analysis.
Avista measure data
NWPCC workbooks, RTF
NWPCC 2021 Plan
conservation workbooksAEG
DEEM
AEO 2019
DEER
Other secondary sources
Applicability
Estimate of the percentage of dwellings in the
residential sector, square feet in the commercial
sector, or employees in the industrial sector where the measure is applicable and where it is technically
feasible to implement.
Avista measure data
NWPCC workbooks, RTF
NWPCC 2021 Plan
conservation workbooks
AEG DEEM
DEER
Other secondary sources
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 872 of 1105
On Market and Off
Market Availability
Expressed as years for equipment measures to reflect
when the equipment technology is available or no
longer available in the market.
AEG appliance standards and
building codes analysis

Data Application for Technical Achievable Potential
To estimate Technical Achievable Potential, two sets of parameters are needed to represent customer decision making behavior with respect to energy-efficiency choices.
• Te chnical d iffusion curves for non-equipment measures. Equipment measures are installed when existing units fail. Non-equipment measures do not have this natural periodicity, so rather than installing all available non-equipment measures in the first year of the projection (instantaneous potential), they are phased in according to adoption schedules that generally align with the diffusion of similar equipment measures. Like the 2019 CPA, we applied the “Retrofit” ramp rates from the 2021 Power Plan directly as diffusion curves. For technical potential, these rates summed up to 100% by the 20th year for all measures.
• Ad option rate s. Customer adoption rates or take rates are applied to technical potential to estimate Technical Achievable Potential. For equipment measures, the Council’s “Lost Opportunity” ramp rates were applied to technical potential with a maximum achievability of 85%-100% depending on the measure. For non-equipment measures, the Council’s “Retrofit” ramp rates have already been applied to calculate technical diffusion. In this case, we multiply each of these by 85% (for most measures) to calculate Technical Achievable Potential. Adoption rates are presented in Appendix B.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 873 of 1105

MARKET CHARACTERIZATION AND MARKET PROFILES
In this section, we describe how customers in the Avista service territory use electricity in the base year of the study, 2019. It begins with a high-level summary of energy use across all sectors and then delves into each sector in more detail.
Energy Use Summary
Total electricity use for the residential, commercial, and industrial sectors for Avista in 2019 was 7,794 GWh; 5,205 GWh (WA) and 2,589 GWh (ID). As shown in the tables below, in both states the residential sector accounts for nearly 50% of annual energy use, followed by commercial at around 40% of annual energy use. In terms of winter peak demand, the total system peak in 2019 was 1,530 MW: 1,060 (WA) and 470 MW (ID). In both states, the residential sector contributes the most to the winter peak.
Figure 3-1 Sector-Level Electricity Use in Base Year 2019, Washington

Table 3-1 Avista Sector Control Totals (2019), Washington
Sector
Total 5,205 100% 1,060 100%

Residential49%
Commerci
al
42%
Industrial
9%
Annual Use (GWh)
Residential
45%
Commerci
al
40%
Industrial
15%
Winter Peak (MW)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 874 of 1105
Figure 3-2 Sector-Level Electricity Use in Base Year 2019, Idaho

Table 3-2 Avista Sector Control Totals (2019), Idaho
Sector
Total 2,589 100% 470 100%
Residential Sector
The total number of households and electricity sales for the service territory were obtained from Avista’s customer database. In 2019, there were 229,171 households in the state of Washington that used a total of 2,539 GWh with winter peak demand of 473 MW. Average use per customer (or household) at 11,080 kWh is about average compared to other regions of the country. We allocated these totals into four residential segments and the values are shown in Table 3-3.
Table 3-4 shows the total number of households and electricity sales in the state of Idaho. In 2019, there were 116,114 households that used a total of 1,236 GWh with winter peak demand of 223 MW. Average use per customer (or household) was 10,643 kWh.
Table 3-3 Residential Sector Control Totals (2019), Washington
Segment Number of
Customers Electricity Use % of Annual Use/Customer Winter Peak
Total 229,171 2,539 100% 11,080 473

Residential
48%
Commercial39%
Industrial13%
Annual Use (GWh)
Residential48%
Commercial38%
Industrial14%
Winter Peak (MW)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 875 of 1105
Table 3-4 Residential Sector Control Totals (2019), Idaho
Segment Number of
Customers
Electricity
Use
% of
Annual
Annual Use/Customer
(kWh/HH)
Winter
Peak
Total 116,114 1,236 100% 10,643 223

As we describe in the previous chapter, the market profiles provide the foundation for development of the baseline projection and the potential estimates. The average market profile for the residential sector is presented in Table 3-5 (WA) and Table 3-6 (ID). Segment-specific market profiles are presented in Appendix A.
Figure 3-3 (WA) and Figure 3-4 (ID) show the distribution of annual electricity use by end use for all customers. Two main electricity end uses —appliances and space heating— account for approximately 55% of total use. Appliances include refrigerators, freezers, stoves, clothes washers, clothes dryers, dishwashers, and microwaves. The remainder of the energy falls into the water heating, lighting, cooling, electronics, and the miscellaneous category – which is comprised of furnace fans, pool pumps, electric vehicles, and other “plug” loads (all other usage not covered by those listed in Table 3-5 and Table 3-6 such as hair dryers, power tools, coffee makers, etc.).
The charts also show estimates of winter peak demand by end use. As expected, heating is the largest contributor to winter peak demand, followed by appliances, lighting, and water heating.
Figure 3-5 (WA) and Figure 3-6 (ID) present the electricity intensities by end use and housing type. Single family homes have the highest use per customer at 11,699 kWh/year (WA) and 11,158 kWh/year (ID).
Figure 3-3 Residential Electricity Use and Winter Peak Demand by End Use (2019), Washington

Cooling7%
Space Heating38%
Water Heating
17%
Interior Lighting7%
Exterior Lighting1%
Appliances
16%
Electronics7%
Miscellaneous
7%
Annual Use by End Use
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 876 of 1105

Figure 3-4 Residential Electricity Use and Winter Peak Demand by End Use (2019), Idaho

Space Heating73%
Water Heating11%
Interior Lighting4%
Exterior Lighting1%
Appliances4%
Electronics
2%Miscellaneous5%
Winter Peak Demand
Cooling6%
Space Heating
37%
Water Heating
13%
Interior Lighting
8%
Exterior Lighting2%
Appliances18%
Electronics7%
Miscellaneous9%
Annual Use by End Use
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 877 of 1105

Figure 3-5 Residential Intensity by End Use and Segment (Annual kWh/HH, 2019), Washington

Cooling0%
Space Heating72%
Water Heating9%
Interior Lighting5%
Exterior Lighting
1%
Appliances5%
Electronics2%
Miscellaneous6%
Winter Peak Demand
0 2000 4000 6000 8000 10000 12000 14000
Single Family
Multi-Family
Mobile Home
Low Income
Total
kWh per Household
Cooling
Space Heating
Water Heating
Interior Lighting
Exterior Lighting
Appliances
Electronics
Miscellaneous
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 878 of 1105
Figure 3-6 Residential Intensity by End Use and Segment (Annual kWh/HH, 2019), Idaho

0 2000 4000 6000 8000 10000 12000 14000
Single Family
Multi-Family
Mobile Home
Low Income
Total
kWh per Household
Cooling
Space Heating
Water Heating
Interior Lighting
Exterior Lighting
Appliances
Electronics
Miscellaneous
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 879 of 1105
Table 3-5 Average Market Profile for the Residential Sector, 2019, Washington
End Use Technology Saturation
Total 11,080 2,539,174

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 880 of 1105
Table 3-6 Average Market Profile for the Residential Sector, 2019, Idaho
End Use Technology Saturation
Total 10,643 1,235,752

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 881 of 1105
Commercial Sector
The total electric energy consumed by commercial customers in Avista’s service area in 2017 was 2,166 GWh (WA) and 1,007 GWh (ID). Avista billing data, CBSA and secondary data were used to allocate this energy usage to building type segments and to develop estimates of energy intensity (annual kWh/square foot). Using the electricity use and intensity estimates, we infer floor space which is the unit of analysis in LoadMAP for the commercial sector. The values are shown in Table 3-7 (WA) and Table 3-8 (ID). The average building intensities by segment are based on regional information from the CBSA, therefore the intensity is the same both states. However, due to the different mix of building types, overall end use mix is different as shown in Figure 3-9 and Figure 3-10.
Table 3-7 Commercial Sector Control Totals (2019), Washington
Segment Electricity Sales % of Total Intensity (GWh) Usage
Small Office 192 9% 15.6
Large Office 507 23% 17.3
Restaurant 113 5% 40.9
Retail 278 13% 12.2
Grocery 193 9% 43.4
College 114 5% 16.2
School 146 7% 9.1
Health 119 5% 23.3
Lodging 86 4% 12.2
Warehouse 95 4% 4.7
Miscellaneous 324 15% 10.3
Total 2,166 100% 13.7

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 882 of 1105
Table 3-8 Commercial Sector Control Totals (2019), Idaho
Segment Intensity
Total 1,007 100% 12.7

Figure 3-7 (WA) and Figure 3-8 (ID) show the distribution of annual electricity consumption and summer peak demand by end use across all commercial buildings. Electric usage is dominated by lighting and ventilation, which comprise almost 44% of annual electricity usage. Lighting and ventilation also make up the largest portions of winter peak, however electric space heating represents a greater part of the peak than it does annual energy.
Figure 3-9 (WA) and Figure 3-10 (ID) presents the electricity usage in GWh by end use and segment. In Washington, Large offices, retail, and miscellaneous buildings use the most electricity in the service territory. For Idaho, Large and Small Offices are more balanced in terms of total consumption. HVAC and lighting are the major end uses across most segments, aside from Large Offices and grocery, where office equipment and refrigeration equipment, respectively, are highly concentrated.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 883 of 1105
Figure 3-7 Commercial Electricity Use and Winter Peak Demand by End Use (2019), Washington

Cooling11%
Space Heating5%
Ventilation
18%
Water Heating2%
Interior Lighting20%Exterior Lighting6%
Refrigeration
11%
Food Preparation3%
Office Equipment10%
Miscellaneous
14%
Annual Use by End Use
Cooling
3%Space Heating
12%
Ventilation
16%
Water Heating4%Interior Lighting24%Exterior Lighting
2%
Refrigeration
9%
Food Preparation
4%
Office Equipment
10%
Miscellaneous16%
Winter Peak Demand
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 884 of 1105
Figure 3-8 Commercial Electricity Use and Winter Peak Demand by End Use (2019), Idaho

Cooling11%
Space Heating7%
Ventilation18%
Water Heating3%
Interior Lighting21%Exterior Lighting
6%
Refrigeration
6%
Food Preparation2%
Office Equipment
10%
Miscellaneous
16%
Annual Use by End Use
Cooling3%
Space Heating16%
Ventilation16%
Water Heating
4%
Interior Lighting24%Exterior Lighting2%
Refrigeration5%
Food Preparation2%
Office Equipment
10%
Miscellaneous18%
Winter Peak Demand
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 885 of 1105
Figure 3-9 Commercial Electricity Usage by End Use Segment (GWh, 2019), Washington

Figure 3-10 Commercial Electricity Usage by End Use Segment (GWh, 2019), Idaho

Table 3-9 (WA) and Table 3-10 (ID) show the average market profile for electricity of the commercial sector as a whole, representing a composite of all segments and buildings. Market profiles for each segment are presented in the appendix to this volume.

0
100
200
300
400
500
600
Cooling
Space Heating
Ventilation
Water Heating
Interior Lighting
Exterior Lighting
Refrigeration
Food Preparation
Office Equipment
Miscellaneous
0
50
100
150
200
250
Cooling
Space Heating
Ventilation
Water Heating
Interior Lighting
Exterior Lighting
Refrigeration
Food Preparation
Office Equipment
Miscellaneous
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 886 of 1105
Table 3-9 Average Electric Market Profile for the Commercial Sector, 2019, Washington
End Use Technology Saturation
Total 13.17 2,166.0
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 887 of 1105
Table 3-10 Average Electric Market Profile for the Commercial Sector, 2019, Idaho
End Use Technology Saturation
Total 11.75 143.0
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 888 of 1105

Industrial Sector
The total electricity used in 2019 by Avista’s industrial customers was 846 GWh; 500 GWh (WA) and 346 GWh (ID). Avista billing data and load forecast, NEEA’s IFSA, and secondary sources were used to develop estimates of energy intensity (annual kWh/employee). Using the electricity use and intensity estimates, we infer the number of employees which is the unit of analysis in LoadMAP for the industrial sector. These are shown in Table 3-11.
Table 3-11 Industrial Sector Control Totals (2019)
State
Electricity Sales Intensity Winter Peak
(GWh) (Annual kWh/employee) (MW)
Washington 500 42,527 164
Idaho 346 29,394 68

Figure 3-12 shows the distribution of annual electricity consumption and summer peak demand by end use for all industrial customers. Motors are the largest overall end use for the industrial sector, accounting for 47% of energy use. Note that this end use includes a wide range of industrial equipment, such as air compressors and refrigeration compressors, pumps, conveyor motors, and fans. The process end use accounts for 25% of annual energy use, which includes heating, cooling, refrigeration, and electro-chemical processes. Lighting is the next highest, followed by cooling, miscellaneous, heating and ventilation.
Table 3-12 and Table 3-13 show the composite market profile for the industrial sector.

Figure 3-11 Industrial Electricity Use and Winter Peak Demand by End Use (2019), All Industries, WA

Cooling4%Space Heating2%Ventilation
11%
Interior Lighting9%
Exterior Lighting2%
Motors
47%
Process
25%
Miscellaneous
0%
Annual Use by End Use
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 889 of 1105

Figure 3-12 Industrial Electricity Use and Winter Peak Demand by End Use (2019), All Industries, ID

Cooling0%
Space Heating3%
Ventilation
8%
Interior Lighting9%
Exterior Lighting
1%
Motors52%
Process27%
Miscellaneous0%
Winter Peak Demand
Cooling4%Space Heating2%
Ventilation11%Interior Lighting9%
Exterior Lighting2%
Motors47%
Process
20%
Miscellaneous5%
Annual Use by End Use
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 890 of 1105

Cooling
0%
Space Heating3%Ventilation
8%
Interior Lighting9%
Exterior Lighting
0%
Motors
52%
Process
22%
Miscellaneous
6%
Winter Peak Demand
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 891 of 1105
Table 3-12 Average Electric Market Profile for the Industrial Sector, 2019, Washington
End Use Technology Saturation EUI Intensity Usage
Cooling Air-Cooled Chiller 2.5% 10,819.85 270.50 3.2
Cooling Air-Source Heat Pump 1.7% 10,077.53 170.41 2.0
Heating Electric Room Heat 2.6% 15,324.53 394.31 4.6
Heating Geothermal Heat Pump 0.0% 1.00 0.00 0.0
Interior Lighting High-Bay Lighting 100.0% 1,912.71 1,912.71 22.5
Exterior Lighting Area Lighting 100.0% 254.16 254.16 3.0
Motors Pumps 100.0% 4,252.64 4,252.64 50.0
Motors Material Handling 100.0% 8,505.29 8,505.29 100.0
Process Process Cooling 100.0% 1,275.79 1,275.79 15.0
Process Process Electrochemical 100.0% 2,625.61 2,625.61 30.9
Total 42,526.45 500.1

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 892 of 1105
Table 3-13 Average Electric Market Profile for the Industrial Sector, 2019, Idaho
End Use Technology Saturation EUI Intensity Usage
Cooling Air-Cooled Chiller 2.5% 15,505.86 387.65 2.2
Cooling Air-Source Heat Pump 1.7% 14,442.05 244.21 1.4
Heating Electric Room Heat 2.6% 21,961.48 565.09 3.2
Heating Geothermal Heat Pump 0.0% 1.00 0.00 0.0
Interior Lighting High-Bay Lighting 100.0% 2,741.09 2,741.09 15.5
Exterior Lighting Area Lighting 100.0% 364.23 364.23 2.1
Motors Pumps 100.0% 6,094.44 6,094.44 34.6
Motors Material Handling 100.0% 12,188.87 12,188.87 69.1
Process Process Cooling 100.0% 1,828.33 1,828.33 10.4
Process Process Electrochemical 100.0% 426.33 426.33 2.4
Total 60,944.36 345.6

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 893 of 1105

BASELINE PROJECTION
Prior to developing estimates of energy-efficiency potential, we developed a baseline end-use projection to quantify what the consumption is likely to be in the future and in absence of any future conservation programs. The savings from past programs are embedded in the forecast, but the baseline projection assumes that those past programs cease to exist in the future. Possible savings from future programs are captured by the potential estimates.
The baseline projection incorporates assumptions about:
• Customer population and economic growth
• Appliance/equipment standards and building codes already mandated (see Chapter 2)
• Forecasts of future electricity prices and other drivers of consumption
• Trends in fuel shares and appliance saturations and assumptions about miscellaneous electricity growth
Although it aligns closely with it, the baseline projection is not Avista’s official load forecast. Rather it was developed to serve as the metric against which EE potentials are measured. This chapter presents the baseline projections we developed for this study. Below, we present the baseline projections for each sector and state, which include projections of annual use in GWh and summer peak demand in MW. We also present a summary across all sectors.
Please note that the base-year for the study is 2019. Annual energy use and summer peak demand values for 2019 reflect weather-normalized values. In future years, energy use and peak demand reflect normal weather, as defined by Avista.
Residential Sector
Annual Use
Table 4-1 (WA) and Table 4-2 (ID) present the baseline projection for electricity at the end-use level for the residential sector as a whole. Overall in Washington, residential use increases from 2,539 GWh in 2019 to 2,976 GWh in 2041, an increase of 17%. Residential use in Idaho increases from 1,236 GWh in 2019 to 1,513 GWh in 2041, an increase of 22%. This reflects a substantial customer growth forecast in both states. Figure 4-1 (WA) and Figure 4-3 (ID) display the graphical representation of the baseline projection.
Figure 4-2 (WA) and Figure 4-4 (ID) present the baseline projection of annual electricity use per household. Most noticeable is that lighting use decreases throughout the time period – this is the combined effect of the RTF market baseline assumption in both states, and is further enhanced in Washington by state lighting standards in effect from 2020 forward.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 894 of 1105
Table 4-1 Residential Baseline Sales Projection by End Use (GWh), Washington
End Use 2019 2022 2023 2026 2031 2041 % Change
('19-'41)
Cooling 187 202 205 218 247 350 87%
Space Heating 956 924 926 932 940 958 0%
Water Heating 420 408 405 398 387 369 -12%
Interior Lighting 177 158 149 118 93 82 -54%
Exterior Lighting 34 28 26 20 16 13 -61%
Appliances 414 425 429 442 463 498 20%
Electronics 170 185 190 206 234 294 73%
Miscellaneous 187 202 207 226 269 461 146%
Generation -5 -7 -8 -11 -18 -48 825%
Total 2,539 2,525 2,529 2,548 2,631 2,976 17%

Figure 4-1 Residential Baseline Projection by End Use (GWh), Washington

0
500
1000
1500
2000
2500
3000
3500
2019 2022 2025 2028 2031 2034 2037 2040
GWh
Cooling
Space Heating
Water Heating
Interior Lighting
Exterior Lighting
Appliances
Electronics
Miscellaneous
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 895 of 1105
Figure 4-2 Residential Baseline Projection by End Use – Annual Use per Household, Washington

Table 4-2 Residential Baseline Sales Projection by End Use (GWh), Idaho
End Use 2019 2022 2023 2026 2031 2041 % Change
('19-'41)
Cooling 77 88 91 102 125 185 142%
Space Heating 457 447 449 455 460 469 2%
Water Heating 157 155 155 153 150 143 -9%
Interior Lighting 106 101 95 73 55 48 -55%
Exterior Lighting 26 20 18 12 9 7 -75%
Appliances 220 229 232 241 253 271 23%
Electronics 85 92 94 101 110 131 54%
Miscellaneous 110 122 126 141 171 285 160%
Generation -3 -4 -4 -6 -9 -25 848%
Total 1,236 1,250 1,256 1,272 1,322 1,513 22%

0
100
200
300
400
500
600
2019 2022 2025 2028 2031 2034 2037 2040
Cooling
Space Heating
Water Heating
Interior Lighting
Exterior Lighting
Appliances
Electronics
Miscellaneous
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 896 of 1105
Figure 4-3 Residential Baseline Projection by End Use (GWh), Idaho

Figure 4-4 Residential Baseline Sales Projection by End Use – Annual Use per Household, Idaho

Commercial Sector Baseline Projections
Annual Use
In Washington, annual electricity use in the commercial sector grows during the overall forecast horizon, starting at 2,166 GWh in 2019, and increasing to 2,811 in 2041, an increase of 30%. In Idaho, annual
0
200
400
600
800
1000
1200
1400
1600
1800
2019 2022 2025 2028 2031 2034 2037 2040
GWh
Cooling
Space Heating
Water Heating
Interior Lighting
Exterior Lighting
Appliances
Electronics
Miscellaneous
0
50
100
150
200
250
300
350
400
450
500
2019 2022 2025 2028 2031 2034 2037 2040
Cooling
Space Heating
Water Heating
Interior Lighting
Exterior Lighting
Appliances
Electronics
Miscellaneous
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 897 of 1105
electricity use grows from 1,007 GWh in 2017 to 1,112 GWh in 2041, an increase of 10%. The tables and graphs below present the baseline projection at the end-use level for the commercial sector as a whole.
Table 4-3 Commercial Baseline Sales Projection by End Use (GWh), Washington
End Use 2019 2022 2023 2026 2031 2041
Cooling 236 250 250 251 254 265 12%
Space Heating 114 112 112 115 120 130 14%
Ventilation 383 379 379 374 365 359 -6%
Water Heating 54 55 55 56 58 63 18%
Interior Lighting 434 417 411 395 388 404 -7%
Exterior Lighting 127 118 115 108 105 107 -16%
Refrigeration 233 243 247 260 283 346 48%
Food Preparation 66 69 70 72 81 106 60%
Miscellaneous 304 341 355 402 492 733 141%
Total 2,166 2,201 2,211 2,252 2,385 2,811 30%
Table 4-4 Commercial Baseline Sales Projection by End Use (GWh), Idaho
End Use 2019 2022 2023 2026 2031 2041
Cooling 114 122 122 124 126 134 18%
Space Heating 68 68 68 70 74 82 20%
Ventilation 185 185 185 184 181 182 -2%
Water Heating 29 30 30 31 32 36 24%
Exterior Lighting 58 56 55 51 49 51 -13%
Food Preparation 23 24 24 25 26 29 25%
Miscellaneous 160 165 167 172 181 201 26%
Total 1,007 1,022 1,023 1,022 1,041 1,112 10%

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 898 of 1105
Figure 4-5 Commercial Baseline Projection by End Use, Washington

Figure 4-6 Commercial Baseline Projection by End Use, Idaho

0
500
1000
1500
2000
2500
3000
3500
2019 2022 2025 2028 2031 2034 2037 2040
GWh
Cooling
Space Heating
Ventilation
Water Heating
Interior Lighting
Exterior Lighting
Refrigeration
Food Preparation
Office Equipment
Miscellaneous
0
200
400
600
800
1000
1200
2019 2022 2025 2028 2031 2034 2037 2040
GWh
Cooling
Space Heating
Ventilation
Water Heating
Interior Lighting
Exterior Lighting
Refrigeration
Food Preparation
Office Equipment
Miscellaneous
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 899 of 1105
Industrial Sector Baseline Projections
Annual Use
Annual industrial use declined by 8% through the forecast horizon, consistent with trends from Avista’s industrial load forecast. The tables and graphs below present the projection at the end-use level. Overall in Washington, industrial annual electricity use decreases from 500 GWh in 2017 to 455 GWh in 2041. In Idaho, annual electricity use drops from 346 GWh in 2019 to 325 GWh in 2041.
Table 4-5 Industrial Baseline Projection by End Use (GWh), Washington
End Use 2019 2022 2023 2026 2031 2041 % Change
('19-'41)
Cooling 21 21 21 20 20 19 -11%
Space Heating 8 8 8 8 8 8 -9%
Ventilation 56 51 51 50 47 42 -24%
Interior Lighting 46 42 42 41 40 38 -17%
Process 125 119 119 119 119 119 -5%
Miscellaneous 0 0 0 0 0 0 76%
Total 500 471 472 468 463 455 -9%

Table 4-6 Industrial Baseline Projection by End Use (GWh), Idaho
End Use 2019 2022 2023 2026 2031 2041 % Change
('19-'41)
Cooling 15 16 16 16 15 13 -9%
Ventilation 39 41 40 38 35 30 -23%
Interior Lighting 32 33 33 31 30 27 -15%
Exterior Lighting 6 6 6 5 5 4 -27%
Process 68 74 73 72 70 66 -3%
Motors 162 177 176 173 168 158 -3%
Miscellaneous 19 21 21 21 22 22 18%
Total 346 374 371 362 349 325 -6%

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 900 of 1105
Figure 4-7 Industrial Baseline Projection by End Use (GWh), Washington

Figure 4-8 Industrial Baseline Projection by End Use (GWh), Idaho

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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 901 of 1105
Summary of Baseline Projections across Sectors and States
Annual Use
Table 4-7 and Figure 4-9 provide a summary of the baseline projection for annual use by sector for the entire Avista service territory. Overall, the projection shows steady growth in electricity use, driven primarily by customer growth forecasts.
Table 4-7 Baseline Projection Summary (GWh), WA and ID Combined
End Use 2019 2022 2023 2026 2031 2041
Residential 3,775 3,774 3,785 3,820 3,953 4,489 19%
Commercial 3,173 3,223 3,234 3,273 3,427 3,924 24%
Industrial 846 845 843 831 812 780 -8%
Total 7,794 7,842 7,863 7,925 8,192 9,193 18%

Figure 4-9 Baseline Projection Summary (GWh), WA and ID Combined

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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 902 of 1105

CONSERVATION POTENTIAL
This section presents the conservation potential for Avista. This includes every measure that is considered in the measure list, regardless of delivery mechanism (program implementation, NEEA initiatives, or momentum savings).
We present the annual energy savings in GWh and aMW, as well as the winter peak demand savings in MW, for selected years. Year-by-year savings for annual energy and peak demand are available in the LoadMAP model, which was provided to Avista at the conclusion of the study.
This section begins a summary of annual energy savings across all three sectors. Then we provide details for each sector. Please note that all savings are provided at the customer meter.
Overall Summary of Energy Efficiency Potential
Summary of Annual Energy Savings
Table 5-1 (WA) and Table 5-2 (ID) summarize the EE savings in terms of annual energy use for all measures for two levels of potential relative to the baseline projection. Figure 5-1(WA) and Figure 5-2 (ID) displays the two levels of potential by year. Figure 5-3 (WA) and Figure 5-4 (ID) display the EE projections.
• Te chnical Potential reflects the adoption of all conservation measures regardless of cost-effectiveness. For Washington, first-year savings are 101 GWh, or 2.0% of the baseline projection. Cumulative savings in 2041 are 1,822 GWh, or 29.2% of the baseline. For Idaho, first-year savings are 58 GWh, or 2.2% of the baseline projection. Cumulative savings in 2041 are 948 GWh, or 32.1% of the baseline.
• Te chnical Achievable Potentia l modifies Technical Potential by accounting for customer adoption constraints. In Washington, first-year savings potential is 56 GWh, or 1.1% of the baseline. In 2041, cumulative technical achievable savings reach 1,309 GWh, or 21.0% of the baseline projection. This results in average annual savings of 1.0% of the baseline each year. Technical Achievable Potential is approximately 72% of Technical Potential in Washington throughout the forecast horizon. For Idaho, first year savings are 3 GWh or 1.2% of the baseline and by 2041 cumulative technical achievable savings reach 665 GWh, or 22.5% of the baseline. This results in average annual savings of 1% of the baseline each year. In Idaho, Technical Achievable Potential reflects 71% of Technical Potential throughout the forecast horizon.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 903 of 1105
Table 5-1 Summary of EE Potential (Annual Energy, GWh), Washington
2022 2023 2024 2031 2041
Baseline projection (GWh) 5,196 5,212 5,229 5,479 6,243
Cumulative Savings (GWh)
Technical Potential 101 209 325 1,247 1,822
Cumulative Savings (aMW)
Achievable Technical Potential 6 14 22 99 149
Cumulative Savings as a % of Baseline
Achievable Technical Potential 1.1% 2.3% 3.7% 15.8% 21.0%
Technical Potential 2.0% 4.0% 6.2% 22.8% 29.2%

Table 5-2 Summary of EE Potential (Annual Energy, GWh), Idaho
2022 2023 2024 2031 2041
Baseline projection (GWh) 2,646 2,650 2,653 2,713 2,951

Achievable Technical Potential 33 70 110 448 665
Technical Potential 58 119 183 654 948
Cumulative Savings (aMW)
Achievable Technical Potential 4 8 13 51 76
Technical Potential 7 14 21 75 108
Cumulative Savings as a % of Baseline
Achievable Technical Potential 1.2% 2.6% 4.1% 16.5% 22.5%
Technical Potential 2.2% 4.5% 6.9% 24.1% 32.1%

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 904 of 1105
Figure 5-1 Summary of EE Potential as % of Baseline Projection (Annual Energy), Washington

Figure 5-2 Summary of EE Potential as % of Baseline Projection (Annual Energy), Idaho

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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 905 of 1105
Figure 5-3 Baseline Projection and EE Forecast Summary (Annual Energy, GWh), Washington

Figure 5-4 Baseline Projection and EE Forecast Summary (Annual Energy, GWh), Idaho

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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 906 of 1105
Summary of Conservation Potential by Sector
Table 5-3 and Figure 5-5 summarize the range of electric Technical Achievable Potential by sector, both states combined. The residential and commercial sectors contribute the most savings, with commercial lighting forming a strong early foundation, and later-blossoming residential potential from measures such as heat pump water heaters growing to surpass commercial savings by years 10-20.
Table 5-3 Technical Achievable Conservation Potential by Sector (Annual Use), WA and ID
2022 2023 2024 2031 2041
Cumulative Savings (GWh)
Residential 32 72 120 623 1,004
Commercial 46 97 152 583 819
Industrial 10 21 33 110 151
Total 88 190 304 1,317 1,974

Cumulative Savings (aMW)
Residential 4 8 14 71 115
Commercial 5 11 17 67 94
Industrial 1 2 4 13 17
Total 10 22 35 150 225

Figure 5-5 Technical Achievable Conservation Potential by Sector (Annual Energy, GWh)

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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 907 of 1105
Residential Conservation Potential
Table 5-4 (WA) and Table 5-5 (ID) present estimates for measure-level conservation potential for the residential sector in terms of annual energy savings. Figure 5-6 (WA) and Figure 5-7 (ID) display the two levels of potential by year. For Washington, Technical Achievable Potential in 2022 is 20 GWh, or 0.8 % of the baseline projection. By 2041, cumulative technical achievable savings are 672 GWh, or 22.6% of the baseline projection. At this level, it represents over 66% of technical potential. For Idaho, 2022 technical achievable savings are 12 GWh or 1.0% of the baseline and by 2040 cumulative technical achievable savings reach 332 GWh, or 21.9% of the baseline. Technical Achievable Potential in Idaho in 2041 is 67% of technical potential.
Table 5-4 Residential Conservation Potential (Annual Energy), Washington
2022 2023 2024 2031 2041
Baseline projection (GWh) 2,525 2,529 2,534 2,631 2,976
Cumulative Savings (GWh)
Achievable Technical Potential 20 45 75 409 672
Technical Potential 49 103 162 655 1,005
Cumulative Savings (aMW)
Achievable Technical Potential 2 5 9 47 77
Technical Potential 6 12 18 75 115
Cumulative Savings as a % of Baseline
Achievable Technical Potential 0.8% 1.8% 3.0% 15.6% 22.6%
Technical Potential 1.9% 4.1% 6.4% 24.9% 33.8%

Table 5-5 Residential Conservation Potential (Annual Energy), Idaho
2022 2023 2024 2031 2041
Baseline projection (GWh) 1,250 1,256 1,262 1,322 1,513
Cumulative Savings (GWh)
Achievable Technical Potential 12 27 45 214 332
Technical Potential 27 56 88 334 494
Cumulative Savings (aMW)
Achievable Technical Potential 1 3 5 24 38
Technical Potential 3 6 10 38 56
Cumulative Savings as a % of Baseline
Achievable Technical Potential 1.0% 2.2% 3.5% 16.2% 21.9%
Technical Potential 2.1% 4.5% 6.9% 25.3% 32.6%
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 908 of 1105
Figure 5-6 Residential Conservation Savings as a % of the Baseline Projection (Annual Energy), Washington

Figure 5-7 Residential Conservation Savings as a % of the Baseline Projection (Annual Energy), Idaho

Below, we present the top residential measures from the perspective of annual energy use. Table 5-6 identifies the top 20 residential measures from the perspective of cumulative technical achievable energy savings potential for Washington in 2023, the second year of potential. The top three measures include ENERGY STAR- Connected Thermostat, Ductless Mini Split Heat Pump (Zonal), and Home Energy Management System (HEMS). Note that technical achievable savings do not screen for cost effectiveness and some measures are expected to be screened out during the IRP process.

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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 909 of 1105
Table 5-6 Residential Top Measures in 2023 (Annual Energy, MWh), Washington
Rank Residential Measure
2023 Cumulative
Energy Savings % of
(MWh) Total
1 ENERGY STAR - Connected Thermostat 4,409 10%
2 Ductless Mini Split Heat Pump (Zonal) 4,280 10%
3 Home Energy Management System (HEMS) 3,428 8%
4 Windows - High Efficiency/ENERGY STAR 2,154 5%
5 Water Heater <= 55 Gal 2,016 5%
6 Insulation - Basement Sidewall Installation 1,826 4%
7 Insulation - Ducting 1,563 3%
8 Windows - Low-e Storm Addition 1,519 3%
9 Building Shell - Air Sealing (Infiltration Control) 1,228 3%
10 Ductless Mini Split Heat Pump with Optimized Controls (Ducted Forced Air) 1,128 3%
11 Connected Line-Voltage Thermostat 1,128 3%
12 Exempted Lighting 1,035 2%
13 Interior Lighting - Occupancy Sensors 1,004 2%
14 Exterior Lighting - Photovoltaic Installation 980 2%
15 Insulation - Floor Upgrade 898 2%
16 General Service Lighting 896 2%
17 Building Shell - Whole-Home Aerosol Sealing 840 2%
18 Insulation - Ceiling Upgrade 804 2%
19 Insulation - Wall Cavity Installation 770 2%
20 Windows - Cellular Shades 685 2% Total of Top 20 Measures 32,591 73%
Total Cumulative Savings 44,799 100%

Figure 5-8 presents forecasts of cumulative energy savings for Washington. Space heating and water heating account for a substantial portion of the savings throughout the forecast horizon. Weatherization, ductless heat pumps, and heat pump water heaters account for a large portion of potential over the 20-year study period. LED lighting, while still present, is reduced in comparison to prior studies, as RTF market baseline assumptions and the Washington state lighting standard have moved a substantial amount of potential from those technologies into the realm of codes and market transformation.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 910 of 1105
Figure 5-8 Residential Technical Achievable Savings Forecast (Cumulative GWh), Washington

Table 5-7 shows the top residential measures for Idaho in 2023. The top three measures include high efficiency windows, Ductless Mini Split Heat Pump (Zonal), and LEDs in General Service Lighting. Since Idaho does not have the same state standard regarding lighting, LEDs for general service have a greater remaining market of potential captured in the CPA. in Note that technical achievable savings do not screen for cost effectiveness and some measures are expected to be screened out during the IRP process.

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Exterior Lighting
Appliances
Electronics
Miscellaneous
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 911 of 1105
Table 5-7 Residential Top Measures in 2022 (Annual Energy, MWh), Idaho
Rank Residential Measure
2023 Cumulative
Energy Savings % of
(MWh) Total
1 Windows - High Efficiency/ENERGY STAR 3,654 13%
2 Ductless Mini Split Heat Pump (Zonal) 2,319 9%
3 General Service Lighting 2,302 8%
4 Home Energy Management System (HEMS) 1,547 6%
5 ENERGY STAR - Connected Thermostat 1,480 5%
6 Windows - Low-e Storm Addition 1,312 5%
7 Insulation - Basement Sidewall Installation 1,107 4%
8 Connected Line-Voltage Thermostat 689 3%
9 Building Shell - Air Sealing (Infiltration Control) 688 3%
10 Water Heater - Faucet Aerators 634 2%
11 Water Heater <= 55 Gal 630 2%
12 Exterior Lighting - Photovoltaic Installation 621 2%
13 Insulation - Ducting 580 2%
14 Insulation - Floor Upgrade 520 2%
15 Interior Lighting - Occupancy Sensors 452 2%
16 Insulation - Wall Cavity Installation 425 2%
17 Insulation - Wall Sheathing 383 1%
18 Insulation - Ceiling Upgrade 376 1%
19 Building Shell - Whole-Home Aerosol Sealing 369 1%
20 Ductless Mini Split Heat Pump with Optimized Controls 357 1% Total of Top 20 Measures 20,445 75%
Total Cumulative Savings 27,260 100%

Figure 5-9 presents forecasts of cumulative energy savings for Idaho. Results are similar to Washington where the majority of the savings come from heating and water heating measures.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 912 of 1105
Figure 5-9 Residential Technical Achievable Savings Forecast (Cumulative GWh), Idaho

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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 913 of 1105
Commercial Conservation Potential
Table 5-8 (WA) and Table 5-9 (ID) present estimates for the two levels of conservation potential for the commercial sector from the perspective of annual energy savings and average MW.
Table 5-8 Commercial Conservation Potential (Annual Energy), WA
2022 2023 2024 2031 2041
Baseline projection (GWh) 2,201 2,211 2,224 2,385 2,811
Cumulative Savings (GWh)
Achievable Technical Potential 30 64 101 397 551
Technical Potential 44 90 139 514 712
Cumulative Savings (aMW)
Achievable Technical Potential 3 7 12 45 63
Technical Potential 5 10 16 59 81
Cumulative Savings as a % of Baseline
Achievable Technical Potential 1.4% 2.9% 4.5% 16.6% 19.6%
Technical Potential 2.0% 4.1% 6.3% 21.5% 25.3%

Table 5-9 Commercial Conservation Potential (Annual Energy), Idaho
2022 2023 2024 2031 2041
Baseline projection (GWh) 1,022 1,023 1,023 1,041 1,112
Cumulative Savings (GWh)
Achievable Technical Potential 16 33 51 186 268
Technical Potential 25 50 76 260 375
Cumulative Savings (aMW)
Achievable Technical Potential 2 4 6 21 31
Technical Potential 3 6 9 30 43
Cumulative Savings as a % of Baseline
Achievable Technical Potential 1.6% 3.2% 5.0% 17.9% 24.1%
Technical Potential 2.5% 4.9% 7.5% 25.0% 33.7%
Figure 5-10 (WA) and Figure 5-11 (ID) display the two levels of potential by year. For Washington, the first year of the projection, Technical Achievable Potential is 30 GWh, or 1.4% of the baseline projection. By 2041, technical achievable savings are 551 GWh, or 19.6% of the baseline projection. Throughout the forecast horizon, Technical Achievable Potential represents about 77% of technical potential. For Idaho, first year technical achievable savings are 16 GWh or 1.6% of the baseline and by 2041, cumulative technical
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 914 of 1105
achievable savings reach 268 GWh, or 24.1% of the baseline. Throughout the forecast horizon, Technical Achievable Potential represents about 71% of technical potential in Idaho.
Figure 5-10 Commercial Conservation Savings (Energy), Washington

Figure 5-11 Commercial Conservation Savings (Energy), Idaho

Below, we present the top commercial measures from the perspective of annual energy use.
Table 5-10 (WA) and Table 5-11 (ID) identify the top 20 commercial-sector measures from the perspective of annual energy savings in 2019. In both states, lighting applications make up three out of the top five measures. Although the market has seen significant penetration of LEDs in some applications, newer systems – particularly those with built-in occupancy sensors or other controls – still represent significant savings opportunities.
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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 915 of 1105
Figure 5-12 (WA) and Figure 5-13 (ID) present forecasts of cumulative energy savings by end use. Lighting savings from interior and exterior applications account for a substantial portion of the savings throughout the forecast horizon, due in part to revised turnover assumptions for C&I lighting consistent with RTF assumptions.
Table 5-5-10 Commercial Top Measures in 2019 (Annual Energy, MWh), Washington
Rank Commercial Measure
2023 Cumulative
Energy Savings % of
(MWh) Total
1 Retrocommissioning 6,538 10%
2 Linear Lighting 5,887 9%
3 Strategic Energy Management 4,771 7%
4 Space Heating - Heat Recovery Ventilator 2,401 4%
5 High-Bay Lighting 2,306 4%
6 General Service Lighting 2,010 3%
7 Chiller - Variable Flow Chilled Water Pump 1,876 3%
8 Exterior Lighting - Photovoltaic Installation 1,857 3%
9 HVAC - Dedicated Outdoor Air System (DOAS) 1,679 3%
10 Interior Lighting - Embedded Fixture Controls 1,568 2%
11 Refrigeration - Evaporative Condenser 1,505 2%
12 Ventilation - Permanent Magnet Synchronous Fan Motor 1,379 2%
13 Thermostat - Connected 1,364 2%
14 Area Lighting 1,317 2%
15 Ventilation - Variable Speed Control 1,084 2%
16 Refrigeration - Variable Speed Compressor 982 2%
17 Ventilation - ECM on VAV Boxes 970 2%
18 RTU - Evaporative Precooler 958 1%
19 HVAC - Economizer Maintenance and Repair 876 1%
20 Water Heater - Solar System 754 1%
Total of Top 20 Measures 42,082 66%
Total Cumulative Savings 64,043 100%

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 916 of 1105
Figure 5-12 Commercial Technical Achievable Savings Forecast (Cumulative GWh), Washington

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Office Equipment
Miscellaneous
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 917 of 1105
Table 5-11 Commercial Top Measures in 2023 (Annual Energy, MWh), Idaho
Rank Commercial Measure
2023 Cumulative
Energy Savings % of
(MWh) Total
1 Linear Lighting 3,251 10%
2 Retrocommissioning 2,780 8%
3 Space Heating - Heat Recovery Ventilator 2,727 8%
4 Strategic Energy Management 2,276 7%
5 High-Bay Lighting 1,817 6%
6 HVAC - Dedicated Outdoor Air System (DOAS) 1,375 4%
7 General Service Lighting 1,171 4%
8 Ductless Mini Split Heat Pump 1,131 3%
9 Chiller - Variable Flow Chilled Water Pump 1,048 3%
10 Exterior Lighting - Photovoltaic Installation 1,016 3%
11 Interior Lighting - Embedded Fixture Controls 902 3%
12 Area Lighting 882 3%
13 Thermostat - Connected 801 2%
14 Ventilation - Permanent Magnet Synchronous Fan Motor 636 2%
15 Ventilation - Variable Speed Control 508 2%
16 Exterior Lighting - Enhanced Controls 477 1%
17 Office Equipment - Advanced Power Strips 473 1%
18 HVAC - Economizer Maintenance and Repair 470 1%
19 Ventilation - ECM on VAV Boxes 460 1%
20 RTU - Evaporative Precooler 439 1% Total of Top 20 Measures 24,638 75%
Total Cumulative Savings 32,778 100%

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 918 of 1105
Figure 5-13 Commercial Technical Achievable Savings Forecast (Cumulative GWh), Idaho

Industrial Conservation Potential
Table 5-12 (WA) and Table 5-13 (ID) present potential estimates at the measure level for the industrial sector, from the perspective of annual energy savings. Figure 5-14 (WA) and Figure 5-15 (ID) display the two levels of potential by year. For Washington, technical achievable savings in the first year, 2022, are 6 GWh, or 1.2% of the baseline projection. In 2041, savings reach 86 GWh, or 18.8% of the baseline projection. For Idaho, technical achievable savings in the first year, 2022, are 4 GWh, or 1.2% of the baseline projection. In 2041, savings reach 65 GWh, or 20.0% of the baseline projection.
Table 5-12 Industrial Conservation Potential (Annual Energy), WA
2022 2023 2024 2031 2041
Baseline projection (GWh) 471 472 471 463 455
Cumulative Savings (GWh)
Achievable Technical Potential 6 12 18 62 86
Technical Potential 8 17 25 78 105
Cumulative Savings (aMW)
Achievable Technical Potential 1 1 2 7 10
Technical Potential 1 2 3 9 12
Cumulative Savings as a % of Baseline
Achievable Technical Potential 1.2% 2.5% 3.8% 13.4% 18.8%
Technical Potential 1.7% 3.5% 5.2% 16.8% 23.1%

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Cooling
Space Heating
Ventilation
Water Heating
Interior Lighting
Exterior Lighting
Refrigeration
Food Preparation
Office Equipment
Miscellaneous
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 919 of 1105
Table 5-13 Industrial Conservation Potential (Annual Energy), Idaho
2022 2023 2024 2031 2041
Baseline projection (GWh) 374 371 368 349 325
Cumulative Savings (GWh)
Achievable Technical Potential 4 10 14 49 65
Technical Potential 6 13 19 60 79
Cumulative Savings (aMW)
Achievable Technical Potential 1 1 2 6 7
Technical Potential 1 1 2 7 9
Cumulative Savings as a % of Baseline
Achievable Technical Potential 1.2% 2.6% 3.9% 13.9% 20.0%
Technical Potential 1.6% 3.4% 5.2% 17.2% 24.3%

Figure 5-14 Industrial Conservation Potential as a % of the Baseline Projection (Annual Energy), Washington

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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 920 of 1105
Figure 5-15 Industrial Conservation Potential as a % of the Baseline Projection (Annual Energy), Idaho

Below, we present the top industrial measures from the perspective of annual energy use.
Table 5-14 and Table 5-15 identify the top 20 industrial measures from the perspective of annual energy savings in 2020. For both states, the top measure is High-Bay Lighting. The measure with the second highest savings is Interior Lighting- Embedded Fixture Controls, and retrocomissioning rounds out the top three in both states.
Figure 5-16 (WA) and Figure 5-17 (ID) present forecasts of energy savings by end use as a percent of total annual savings and cumulative savings. Various motor savings and lighting make up the majority of savings potential in the study horizon.
0%
5%
10%
15%
20%
25%
30%
2022 2023 2024 2031 2041
%
o
f

Ba
s
e
l
i
n
e
Achievable Technical Potential Technical Potential
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 921 of 1105
Table 5-14 Industrial Top Measures in 2023 (Annual Energy, GWh), Washington
Rank Industriall Measure
2023 Cumulative
Energy Savings % of
(MWh) Total
1 High-Bay Lighting 3,542 30%
2 Interior Lighting - Embedded Fixture Controls 862 7%
3 Retrocommissioning 740 6%
4 Fan System - Equipment Upgrade 656 5%
5 Strategic Energy Management 613 5%
6 Fan System - Flow Optimization 550 5%
7 Compressed Air - Leak Management Program 379 3%
8 Material Handling - Variable Speed Drive 378 3%
9 Pumping System - System Optimization 342 3%
10 Interior Lighting - Networked Fixture Controls 303 3%
11 Interior Fluorescent - Delamp and Install Reflectors 252 2%
12 Compressed Air - End Use Optimization 246 2%
13 LED Lighting for Indoor Agriculture 236 2%
14 Pumping System - Variable Speed Drive 225 2%
15 Fan System - Variable Speed Drive 215 2%
16 Exterior Lighting - Photovoltaic Installation 205 2%
17 Interior Lighting - Skylights 193 2%
18 Ventilation 179 1%
19 Pumping System - Equipment Upgrade 171 1%
20 Advanced Refrigeration Controls 166 1% Total of Top 20 Measures 10,454 87%
Total Cumulative Savings 11,959 100%

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 922 of 1105
Figure 5-16 Industrial Technical Achievable Savings Forecast (Cumulative GWh), Washington

Table 5-15 Industrial Top Measures in 2019 (Annual Energy, GWh), Idaho
Rank Industrial Measure
2023 Cumulative
Energy Savings % of
(MWh) Total
1 High-Bay Lighting 2,514 26%
2 Interior Lighting - Embedded Fixture Controls 613 6%
3 Retrocommissioning 550 6%
4 Fan System - Equipment Upgrade 518 5%
5 Strategic Energy Management 485 5%
6 Fan System - Flow Optimization 435 5%
7 Compressed Air - Equipment Upgrade 396 4%
8 Compressed Air - Leak Management Program 299 3%
9 Material Handling - Variable Speed Drive 299 3%
10 Pumping System - System Optimization 270 3%
11 Destratification Fans (HVLS) 241 3%
12 Interior Lighting - Networked Fixture Controls 215 2%
13 Interior Fluorescent - Delamp and Install Reflectors 199 2%
14 Compressed Air - End Use Optimization 194 2%
15 LED Lighting for Indoor Agriculture 184 2%
16 Pumping System - Variable Speed Drive 178 2%
17 Fan System - Variable Speed Drive 170 2%
18 Exterior Lighting - Photovoltaic Installation 161 2%
19 Pumping System - Equipment Upgrade 135 1%
20 Interior Lighting - Skylights 126 1% Total of Top 20 Measures 8,184 86%
Total Cumulative Savings 9,510 100%
0
10
20
30
40
50
60
70
80
90
100
2022 2025 2028 2031 2034 2037 2040 2043
GWh
Cooling
Space Heating
Ventilation
Interior Lighting
Exterior Lighting
Motors
Process
Miscellaneous
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 923 of 1105
Figure 5-17 Industrial Technical Achievable Savings Forecast (Annual Energy, GWh), Idaho

0
10
20
30
40
50
60
70
80
2022 2025 2028 2031 2034 2037 2040 2043
GWh
Cooling
Space Heating
Ventilation
Interior Lighting
Exterior Lighting
Motors
Process
Miscellaneous
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 924 of 1105
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 925 of 1105

DEMAND RESPONSE POTENTIAL
In 2014, AEG and The Brattle Group performed an assessment of winter demand response potential for Avista’s commercial and industrial (C&I) sectors. As part of this conservation potential assessment, Avista asked AEG to update the DR analysis for C&I sectors in Washington and Idaho. In 2016, AEG provided an update to the 2014 assessment. For the 2019 study, Avista asked that AEG include the demand response potential for their residential sector and since Avista is a dual-peaking utility, AEG was asked to provide summer demand response potential as well. This year for the 2020 study, to achieve a more accurate representation of ancillary services, viable programs were evaluated on an individual basis for ancillary savings potential.
The updated analysis provides demand response potential and cost estimates for the 24-year planning horizon of 2022-2045 to inform the development of Avista’s 2021 Integrated Resource Plan (IRP). It primarily seeks to develop reliable estimates of the magnitude, timing, and costs of DR resources likely available to Avista over the 24-year planning horizon. The analysis focuses on resources assumed achievable during the planning horizon, recognizing known market dynamics that may hinder resource acquisition. DR analysis results will also be incorporated into subsequent DR planning and program development efforts.
This section describes our analysis approach and the data sources used to develop potential and cost estimates. The following three steps broadly outline our analysis approach:
1. Segment residential service, general service, large general service, and extra-large general service customers for DR analysis and develop market characteristics (customer count and coincident peak demand values) by segment for the base year and planning period.
2. Identify and describe the relevant DR programs and develop assumptions on key program parameters for potential and cost analysis.
3. Assess achievable potential by DR program for the 2022-2045 planning period and estimate program budgets and levelized costs.
Market Characterization
The first step in the DR analysis was to segment customers by service class and develop characteristics for each segment. The two relevant characteristics for DR potential analysis are the number of eligible customers in each market segment and their coincident peak demand.
Market segmentation
Like the 2014, 2016, and 2019 studies, we used Avista’s rate schedules as the basis for customer segmentation by state and customer class. Table 6-1 summarizes the market segmentation we developed for this study.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 926 of 1105
Table 6-1 Market Segmentation
Market Dimensions Segmentation Variable Description
1 State Idaho
Washington
2 Customer Class
By rate schedule:
Residential Service
General Service: Rate Schedule 11
Large General Service: Rate Schedule 21
Extra Large General Service: Rate Schedule 2510
We excluded Avista’s two largest industrial customers from our analysis because they are so large and unique that a segment-based modeling approach is not appropriate. To accurately estimate demand reduction potential for these customers, we would need to develop a detailed understanding of their industrial processes and associated possibilities for load reduction. We would also need to develop specific DR potential estimates for each customer. Avista may wish to engage with these large customers directly to gauge interest in participating in DR programs.
Customer Counts by Segment
Once the customer segments were defined, we developed customer counts and coincident peak demand values for the three C&I segments. We developed these estimates separately by state for Washington and Idaho. We considered 2019 as the base year for the study, since this is the most recent year with a full 12 months of available customer data. This also coincides with the base year used for the CPA study. The forecast years are 2022 to 2045.
Avista provided actual customer counts by rate schedule for Washington and Idaho over the 2016-2019 timeframe and forecasted customer counts over the 2020-2025 period. We used this data to calculate the growth rate across the final two years of the forecast. We then applied these growth rates to develop customer projections over the rest of the study timeframe, 2026-2045. The average annual growth rate for all sectors is 1.1%. Table 6-2 below shows the number of customers by state and customer class for the base year and selected future years.

Table 6-2 Baseline C&I Customer Forecast by State and Customer Class
Customer Class 2022 2025 2035 2045
Washington
General Service 23,328 24,029 26,470 29,159
Large General Service 1,847 1,840 1,822 1,808
Extra Large General Service 22 22 22 22
Total 260,146 267,489 292,881 320,712

10 Excluding the two largest Schedule 25 and Schedule 25P customers.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 927 of 1105

Customer Class 2022 2025 2035 2045
Idaho
Residential Service 120,797 125,479 141,680 159,973
General Service 16,897 17,505 19,692 22,158
Large General Service 1,012 1,007 992 982
Extra Large General Service 11 11 11 11
Total 138,717 144,002 162,376 183,124

Forecasts of Winter and Summer Peak Demand
System Peak Demand
Avista provided the 2019 system winter and summer peak values as well as annual energy forecasts through 2025. AEG used the growth rate across the final two forecasted years by state and sector to forecast annual peak demands through 2045, Table 6-3 shows the winter and summer system peaks for the base year and selected futures years. These peaks exclude the demand for Avista’s largest industrial customers. The winter and summer system peaks are each expected to increase around 10% between 2022-2045.
Table 6-3 Baseline System Winter Peak Forecast (MW @Meter) 11
Peak Demand 2022 2025 2035 2045
Winter System Peak 1,331 1,349 1,403 1,444
Summer System Peak 1,369 1,389 1,446 1,508

Coincident Peak Demand by Segment
To develop the coincident peak forecast for each segment, we started with electricity sales by customer class. Avista provided actual electricity sales for the years 2016-2019 and forecasted electricity sales by rate schedule for the years 2020 through 2025. For the remaining years of the forecast, 2026 through 2045, we projected electricity sales using the growth rate from the last two years of each forecast timeframe.
Next, we relied on electricity sales and coincident peak demand values for 2010 provided in the 2010 load research study conducted by Avista to calculate the load factors for Residential Service, General Service, Large General Service, and Extra Large General Service customers for Washington and Idaho. We then applied the load factors to the 2019 electricity sales data to derive coincident peak demand estimates for the four segments. Table 6-4 and Table 6-5 below show the load factors and coincident peak values for the base year and selected future years.
11 The system peak forecast shown here is the net native load forecast from data provided by Avista, excluding the two largest industrial loads.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 928 of 1105
Table 6-4 Winter Load Factors and Baseline Coincident Peak Forecast by Segment (MW @Meter)
Customer Class Load Factor 2022 2025 2035 2045
Washington
Residential 0.63 473 481 502 522
General Service 0.60 82 85 93 103
Large General Service 0.60 185 184 182 180
Extra Large General Service 0.68 83 83 83 84
Total 823 834 861 889
Idaho
Residential 0.65 226 232 252 274
General Service 0.66 65 67 75 85
Large General Service 0.66 91 90 87 85
Extra Large General Service 0.60 49 49 47 45
Total 431 437 461 489

Table 6-5 Summer Load Factors and Baseline Coincident Peak Forecast by Segment (MW @Meter)
Customer Class Load Factor 2022 2025 2035 2045
Washington
Residential 0.50 509 518 540 562
General Service 0.51 83 85 94 103
Large General Service 0.51 186 185 183 181
Extra Large General Service 0.65 74 74 75 75
Total 852 863 892 922
Idaho
Residential 0.53 237 243 264 287
General Service 0.57 64 66 75 84
Large General Service 0.57 90 89 86 84
Extra Large General Service 0.53 48 47 45 44
Total 438 445 470 499

System and Coincident Peak Forecasts by State
The next step in market characterization is to define the estimated peak load forecast for the study timeframe. This is done at the Avista system level, and also by state. We used Avista’s peak demand data
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 929 of 1105
to develop the individual state contribution to the estimated coincident peak values. These represent a state’s projected demand at the time of the system peak for both summer and winter.
Figure 6-1 shows the statewide contribution to the estimated system coincident summer peak, developed based on load forecast data provided by Avista. In 2022, system peak load for the summer is 1,369 MW at the grid or generator level. Washington contributes 66% of summer system peak while Idaho contributes 34%. Summer coincident peak load is expected to grow by an average of 0.42% annually from 2022-2044.
Figure 6-1 Contribution to Estimated System Coincident Peak Forecast by State (Summer)

Figure 6-2 shows the jurisdictional contribution to the estimated system coincident winter peak forecast, developed based on load forecast data provided by Avista. In 2022, system peak load for the winter (a typical December weekday at 6:00 pm) is 1,331 MW at the grid or generator level. The winter system peak is about 3% lower than the summer peak. Washington contributes 66% of winter system peak while Idaho contributes 34%. Over the study period, winter coincident peak load is expected to grow by an average of 0.41% annually.
-
200
400
600
800
1,000
1,200
1,400
1,600
MW
Washington Idaho
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 930 of 1105
Figure 6-2 Contribution to Estimated System Coincident Peak Forecast by State (Winter)

Equipment End Use Saturation
Another key component of market characterization for DR analysis is end use saturation data. This is required to further segment the market and identify eligible customers for direct control of different equipment options. The relevant space heating equipment for DR analysis are electric furnaces and air-source heat pumps. We obtained C&I saturation data from the CPA study, which had updated figures from the 2019 NEEA Commercial Building Stock Assessment (CBSA). We obtained Residential saturation data from the 2016 NEEA Residential Building Stock Assessment (RBSA). Table 6-6 and Table 6-7 below show saturation estimates by state and customer class for Washington and Idaho respectively. We assume slight growth trends in Central AC, Space Heating, and Electric Vehicle saturations through 2040. For AMI, Avista began their rollout in Washington in 2019 and expects to complete it by the end of 2020. Currently Avista has 99.5% of their rollout complete in their electric only service areas in Washington. In Idaho, the AMI rollout is projected to begin in 2022 and be complete by 2024.
-
200
400
600
800
1,000
1,200
1,400
1,600
MW
Washington Idaho
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 931 of 1105
Table 6-6 2019 End Use Saturations by Customer Class, Washington
End Use Saturation by Equipment Type Residential C&I
Space Heating Saturation
Air-Source Heat Pump 40.8% 14.2%
Total (Applicable for DR Analysis) 40.8% 14.2%
Water Heating Saturation
CTA-2045 Water Heater 0.0% 0.0%
Electric Vehicle Saturation

Central AC Saturation
All Equipment 27.8% 27.8%
AMI Saturation
All Equipment 2.0% 2.0%
Appliance Saturation

Table 6-7 2019 End Use Saturation by Customer Class, Idaho
End Use Saturation by Equipment Type Residential C&I
Space Heating Saturation
Air-Source Heat Pump 40.8% 14.2%
Total (Applicable for DR Analysis) 40.8% 14.2%
Water Heating Saturation
Electric Resistance Water Heater 52.2% 60.1%

All equipment 0.8% -
Central AC Saturation
All Equipment 27.8% 27.8%
AMI Saturation
All Equipment 0.0% 0.0%
Appliance Saturation
All Equipment 100.0% -

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 932 of 1105
DSM Program Options
The next step in the analysis is to characterize the available DSM options for the Avista territory. We considered the characteristics and applicability of a comprehensive list of options available in the DSM marketplace today as well as those projected into the 24-year study time horizon. We included for quantitative analysis those options which have been deployed at scale such that reliable estimates exist for cost, lifetime, and performance. Each selected option is described briefly below.
Program Descriptions
Direct Load Control of Central Air Conditioners
The DLC Central AC program targets Avista’s Residential and General Service customers in Washington and Idaho. This program directly controls Central AC load in summer through a load control switch placed on a customer’s AC unit. During events, the AC units will be cycled on and off. Participation in the program is expected to be shared with the Smart Thermostat- Cooling Program in the integrated scenario since the programs are similar. However, if only one program is rolled out of the two, then participation would be expected to double for the program implemented. In the fully integrated case, we assume it would take three full time employees to manage all the DLC programs (five total).
The DLC Domestic Hot Water Heater program targets Avista’s Residential and General Service customers in Idaho. This program directly controls water heating load throughout the year for these customers through a load control switch. Water heaters would be completely turned off during the DR event period. The event period is assumed to be 50 hours during the summer months and another 50 hours during winter months. Water heaters of all sizes are eligible for control. We assume a $160 cost to Avista for each switch, a $200 installation fee, and a permit and license cost of $100 for residential participants ($125 for general service participants).
The CTA-2045 Hot Water Heater program targets Avista’s Residential and General Service customers in Washington. These water heaters contain a communicating module interface and can seamlessly fit into a DR program as these become more prevalant in the Avista territory. Idaho is not mandating this equipment yet and therefore this program is only modeled for Washington. Water heaters would be completely turned off during the DR event period. The event period is assumed to be 75 hours during the summer months and another 75 hours during winter months. Water heaters of all sizes are eligible for control. We assume a $150 cost to Avista for each module as well as an additional provisioning cost of $100 for each customer (since only 20% of customers will need help provisioning, so we assume a $20 average provisioning cost.)
This program uses the two-way communicating ability of smart thermostats to cycle them on and off during events. The Smart Thermostat program targets Avista’s Residential and General Service customers in Washington and Idaho. We assume this will be a Bring your own Thermostat program (BYOT) and therefore assume no installation costs to Avista. Since the cooling and heating programs are quite different as far as impact assumptions and participation rates, we modeled them separately. As mentioned in the DLC Central AC program description, participation in the DLC Smart Thermostat Cooling program is expected to be split between the two programs in the integrated scenario.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 933 of 1105
The Smart Appliances DLC program uses a Wi-Fi hub to connect smart Wi-Fi enabled appliances such as washers, dryers, refrigerators, and water heaters. During events throughout the year, the smart appliances will be cycled on and off. The Smart Appliances DLC program targets Avista’s Residential and General Service customers in Washington and Idaho. We assume a low steady-state participation rate of 5% for this program.
Third Party Contracts are assumed to be available for General Service, Large General Service, and Extra Large General Service customers year-round. For the Large and Extra Large General Service customers, we assume they will engage in firm curtailment. Under this program option, it is assumed that participating customers will agree to reduce demand by a specific amount or curtail their consumption to a predefined level at the time of an event. In return, they receive a fixed incentive payment in the form of capacity credits or reservation payments (typically expressed as $/kW-month or $/kW-year). Customers are paid to be on call even though actual load curtailments may not occur. The amount of the capacity payment typically varies with the load commitment level. In addition to the fixed capacity payment, participants typically receive a payment for energy reduction during events. Because it is a firm, contractual arrangement for a specific level of load reduction, enrolled loads represent a firm resource and can be counted toward installed capacity requirements. Penalties may be assessed for under-performance or non-performance. Events may be called on a day-of or day-ahead basis as conditions warrant.
This option is typically delivered by load aggregators and is most attractive for customers with maximum demand greater than 200 kW and flexibility in their operations. Industry experience indicates that aggregation of customers with smaller sized loads is less attractive financially due to lower economies of scale. In addition, customers with 24x7 operations, continuous processes, or with obligations to continue providing service (such as schools and hospitals) are not often good candidates for this option.
For the general service customers, we simulate a demand buyback program. In a demand buyback program, customers volunteer to reduce what they can on a day-ahead or day-of basis during a predefined event window. Customers then receive an energy payment based on their performance during the events.
DLC Smart Chargers for Electric Vehicles can be switched off during on-peak hours throughout the year to offset demand to off-peak hours. Avista currently has an Electric Vehicle Supply Equipment (EVSE) pilot program in place for residential, commercial electric vehicle fleets, and workplace charging locations. In 2018, we based our assumptions off of the EVSE pilot results. However, this year Avista revised several program assumptions internally and AEG used those numbers for the study. The program start year was updated to 2024 to reflect technology rollout, the peak reduction was increased, annual O&M Costs were lowered, the Cost of Equipment was lowered, and the annual incentive costs were removed in lieu of a rebate or the utility providing a rate-based charger to participate in the program.
The Time-of-Use (TOU) pricing rate is a standard rate structure where rates are lower during off-peak hours and higher during peak hours during the day incentivizing participants to shift energy use to periods of lower grid stress. For the TOU rate, there are no events called and the structure does not change during the year. Therefore, it is a good default rate for customers that still offers some load shifting potential. We assume two scenarios for the TOU rate. An opt-in rate where participants will have to choose to go on the
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 934 of 1105
rate and an opt-out rate where participants will automatically be placed on the TOU rate and will need to request a rate change if required. We assume this rate will be available to all service classes.
Va riable Peak Pricing
The Variable Peak Pricing (VPP) rate is composed of significantly higher prices during relatively short critical peak periods on event days to encourage customers to reduce their usage. VPP is usually offered in conjunction with a time-of-use rate, which implies at least three time periods: critical peak, on-peak and off-peak. The customer incentive is a more heavily discounted rate during off-peak hours throughout the year (relative a standard TOU rate). Event days are dispatched on relatively short notice (day ahead or day of) typically for a limited number of days during the year. Over time, event-trigger criteria become well-established so that customers can expect events based on hot weather or other factors. Events can also be called during times of system contingencies or emergencies. We assume that this rate will be offered to all service classes
Ancillary Services refer to functions that help grid operators maintain a reliable electricity system. Ancillary services maintain the proper flow and direction of electricity, address imbalances between supply and demand, and help the system recover after a power system event. In systems with significant variable renewable energy penetration, additional ancillary services may be required to manage increased variability and uncertainty. We assume ancillary services demand response capabilities can be available in all sectors. This year we modeled individual ancillary programs based on several parent programs: Smart Thermostats- Heating/Cooling, DLC Water Heating, CTA-2045 Water Heating, Electric Vehicle Charging, and Battery Energy Storage.
Ice Energy Storage, a type of thermal energy storage, is an emerging technology that is being explored in many peak-shifting applications across the country. This technology involves cooling and freezing water in a storage container so that the energy can be used at a later time for space cooling. More specifically, the freezing water takes advantage of the large amount of latent energy associated with the phase change between ice and liquid water, which will absorb or release a large amount of thermal energy while maintaining a constant temperature at the freezing (or melting) point. An ice energy storage unit turns water into ice during off-peak times when price and demand for electricity is low, typically night time. During the day, at peak times, the stored ice is melted to meet all or some of the building’s cooling requirements, allowing air conditioners to operate at reduced loads.
Ice energy storage is primarily being used in non-residential buildings and applications, as modeled in this analysis, but may see expansion in the future to encompass smaller, residential systems as well as emerging grid services for peak shaving and renewable integration. Since the ice energy storage is used for space cooling, we assume this program would be available during the summer months only.
This program provides the ability to shift peak loads using stored electrochemical energy. Currently the main battery storage equipment uses Lithium-Ion Batteries. They are the most cost-effective battery type on the market today. We assume the battery energy storage option will be available for all service classes with the size and cost of the battery varying depending upon the level of demand of the building.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 935 of 1105
Behavioral DR is structured like traditional demand response interventions, but it does not rely on enabling technologies nor does it offer financial incentives to participants. Participants are notified of an event and simply asked to reduce their consumption during the event window. Generally, notification occurs the day prior to the event and are deployed utilizing a phone call, email, or text message. The next day, customers may receive post-event feedback that includes personalized results and encouragement.
For this analysis, we assumed the Behavioral DR program would be offered as part of a Home Energy Reports program in a typical opt-out scenario. As such, we assume this program would be offered to residential customers only. Avista does not currently have a Home Energy Report program in place. Therefore, the Behavioral program is expected to bear the full cost of the program implementation.
Program Assumptions and Characteristics
Table 6-8 lists the DSM options considered in the study, including the eligible sectors, the mechanism for deployment and the expected annual event hours (summer and winter hours combined if both seasons are considered). The 2018 study revised the 2016 study by adding Space Heating as an additional option, however Avista ultimately decided the Smart Thermostat DLC Heating program would be sufficient for DLC space heating options. For cooling, both Central AC DLC and Smart Thermostats DLC were considered as options. 2018 was also the first year that the CTA-2045 Water Heaters were considered as an option. In 2020, several other changes were made to provide a more realistic forecast of DR potential. Since CTA-2045 Water Heaters are only being mandated in Washington, we used a DLC Water Heating program for Idaho instead. Real Time Pricing was removed as a rate option as it is becoming more of a rarely implemented program. In addition, ancillary services were broken out this year as subsets of viable parent programs to capture a more accurate depiction of their potential savings.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 936 of 1105
Table 6-8 Class 1 DSM Products Assessed in the Study
DSM Option Eligible Sectors Mechanism
Annual
Event
Hours
DLC of central air
conditioners
Residential, General
Service
Direct load control switch installed on customer’s
equipment. 100
DLC of domestic hot
water heaters
(DHW)
Residential, General
Service
Direct load control switch installed on customer’s
equipment. 100
CTA-2045 hot water
heaters
Residential, General
Service Communicating module installed on water heater 150
Smart Thermostats
DLC Heating
Residential, General
Service Internet-enabled control of thermostat set points 36
Smart Thermostats
DLC Cooling
Residential, General
Service Internet-enabled control of thermostat set points 36
Smart Appliances
DLC
Residential, General
Service
Internet-enabled control of operational cycles of
white goods appliances 1056
Thermal Energy
Storage
General Service, Large
General Service, Extra
Large General Service
Peak shifting of space cooling loads using stored
ice 72
Third Party
Contracts
General Service, Large
General Service, Extra
Large General Service
Customers enact their customized, mandatory
curtailment plan. Penalties apply for non-
performance. 60
Electric Vehicle DLC
Smart Chargers Residential Automated, level 2 EV chargers that postpone or
curtail charging during peak hours. 1056
Time-of-Use Pricing All Sectors
Higher rate for a particular block of hours that
occurs every day. Requires either on/off peak
meters or AMI technology. 1056
Variable Peak Pricing All Sectors
Much higher rate for a particular block of hours
that occurs only on event days. Requires AMI
technology. 80
Ancillary Services All Sectors
Automated control of various building
management systems or end-uses through one of
the mechanisms already described
varies by
program
Thermal Energy
Storage
General Service, Large
General Service, Extra
Large General Service
Peak shifting of primarily space cooling or heating
loads using a thermal storage medium such as
water or ice
72
Battery Energy
Storage All Sectors
Peak shifting of loads using stored
electrochemical energy

72
Behavioral Residential
Voluntary DR reductions in response to
behavioral messaging. Example programs exist in
CA and other states. Requires AMI technology. 80
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 937 of 1105
The description of options below includes the key assumptions used for potential and levelized cost calculations. The development of these assumptions is based on findings from research and review of available information on the topic, including national program survey databases, evaluation studies, program reports, regulatory filings. The key parameters required to estimate potential for a DSM program are participation rate, per participant load reduction and program costs. We have described below our assumptions of these parameters.
Table 6-9 below shows the steady-state participation rate assumptions for each DSM option as well as the basis for the assumptions. As previously mentioned, the participation for space cooling is split between DLC Central AC and Smart Thermostat options.
Table 6-9 DSM Steady-State Participation Rates (% of eligible customers)
DSM Option Residential
Service
General
Service
Large
General
Service
Extra Large General
Service Basis for Assumption
Direct Load
Control (DLC) of
central air
conditioners
10% 10% - - NWPC DLC Switch cooling
assumption
DLC of domestic
hot water
heaters (DHW)
15% 5% - - Industry Experience- Brattle
Study
Smart
Thermostats
DLC Heating 5% 3% - - Agreed Upon Estimate with
Avista
CTA-2045 hot
water heaters 50% 50% - - NWPC Grid Interactive
Water Heater Assumptions
Smart
Thermostats
DLC Cooling
20% 20% - -
NWPC Smart Thermostat
cooling assumption (See
DLC Central AC)
Smart
Appliances DLC 5% 5% - -
2017 ISACA IT Risk Reward
Barometer – US Consumer
Results, October 2017
Third Party
Contracts - 15% 22% 21% Industry Experience
Electric Vehicle
DLC Smart
Chargers
25% - - -
NWPC Electric Resistance
Grid-Ready Summer/Winter
Participation
Time-of-Use
Pricing Opt-in 13% 13% 13% 13% Best estimate based on
industry experience; Winter
impacts ½ of summer
impacts Time-of-Use
Pricing Opt-out 74% 74% 74% 74%
Variable Peak
Pricing 25% 25% 25% 25% OG&E 2019 Smart Hours
Study
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 938 of 1105
Thermal Energy
Storage - 0.5% 1.5% 1.5% Industry Experience
Battery Energy
Storage 0.5% 0.5% 0.5% 0.5% Industry Experience
Behavioral 20% - - - PG&E rollout with six waves
(2017)

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 939 of 1105
Load Reduction Assumptions
Table 6-10 presents the per participant load reductions for each DSM option and explains the basis for these assumptions. The load reductions are shown on a kW basis for technology-based options and a percent load reduction otherwise.
Table 6-10 DSM Per Participant Impact Assumptions
DSM Option Residential General
Service
Large
General
Service
Extra
Large
General
Service
Basis for Assumption
Direct Load
Control (DLC)
of central air
conditioners
0.5 kW 1.25 kW - -
NWPC DLC Switch cooling assumption was close
to 1.0 kW reduced to adjust for Avista proposed
cycling strategy,
DLC of
domestic hot
water heating
(DHW)
0.50 kW 1.26 kW - -
NWPC Electric Resistance Switch Summer Impact,
General Service is 2.52x that of Residential based
on DLC Central AC Residential to C&I ratio

CTA-2045
Water Heating 0.50 kW 1.26 kW - -
NWPC Electric Resistance Grid-Ready
Summer/Winter Impact, General Service is 2.52x
that of Residential based on DLC Central AC
Residential to C&I ratio
Smart
Thermostats
DLC Heating 1.09 kW 1.35 kW - - NWPC Smart thermostat heating assumption
(east)
Smart
Thermostats
DLC Cooling
0.50 kW 1.25 kW - -
NWPC DLC Switch cooling assumption was close
to 1.0 kW reduced to adjust for Avista proposed
cycling strategy
Smart
Appliances DLC 0.14 kW 0.14 kW - -
Ghatikar, Rish. Demand Response Automation in
Appliance and Equipment. Lawrence Berkley
National Laboratory, 2017.
Third Party
Contracts - 10% 21% 21%
Impact Estimates from Aggregator Programs in
California (Source: 2012 Statewide Load Impact
Evaluation of California Aggregator Demand Response Programs Volume 1: Ex post and Ex
ante Load Impacts; Christensen Associates Energy
Consulting; April 1, 2013).
Electric Vehicle
DLC Smart
Chargers
0.50 kW - - - Avista EVSE DR Pilot Program and other Avista
research
Time-of-Use
Pricing Opt-in 5.7% 0.2% 2.6% 3.1% Best estimate based on industry experience;
Winter impacts ½ of summer impacts Time-of-Use
Pricing Opt-out 3.4% 0.2% 2.6% 3.1%
Variable Peak
Pricing 10% 4% 4% 4% OG&E 2019 Smart Hours Study; Summer Impacts
Shown (Winter impacts ¾ summer)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 940 of 1105
DSM Option Residential General
Service
Large
General
Service
Extra
Large
General
Service
Basis for Assumption
Thermal Energy
Storage 1.68 kW 8.4 kW 8.4 kW
Ice Bear Tech Specifications, https://www.ice-
energy.com/wp-content/uploads/2016/03/ICE-
BEAR-30-Product-Sheet.pdf
Battery Energy
Storage 2 kW 2 kW 15 kW 15 kW Typical Battery size per segment
Behavioral 2% - - - Opower documentation for BDR with Consumers
and Detroit Energy
Program Costs
Table 6-11 shows the annual marketing, recruitment, incentives, and program development costs associated with each DSM option.
Table 6-12 presents itemized cost assumptions for the DSM Options and the basis for the assumptions for the state of Washington. Table 6-11 shows the annual O&M costs per participant and per MW (Third Party Contracts only) and the Cost of Equipment and installation per participant and per kW (Thermal Energy Storage only).
Table 6-11 DSM Program Operations Maintenance, and Equipment Costs (Washington)
DSM Option Annual O&M Cost Per Participant Annual O&M
Cost per MW
Cost of Equip
+ Install Per
Participant
Cost of Equip
+ Install per
kW
DLC Central AC $13.00 $260.00 $0.00

CTA-2045 Water Heating $0.00 $170.00 $0.00
DLC Smart Thermostats – Heating $44.00 $0.00 $0.00
DLC Smart Thermostats - Cooling $44.00 $0.00 $0.00
DLC Smart Appliances $0.00 $300.00 $0.00
Third Party Contracts $0.00 $80,000.00 $0.00 $0.00

Time-of-Use Opt-in $0.00 $0.00 $0.00
Time-of-Use Opt-out $0.00 $0.00 $0.00
Variable Peak Pricing Rates $0.00 $0.00 $0.00
Thermal Energy Storage $308.00 $0.00 $6,160.00
Battery Energy Storage $0.00 $27,897.60 $0.00
Behavioral $3.25 $0.00 $0.00
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 941 of 1105
Table 6-12 shows the annual marketing, recruitment, incentives, and program development costs associated with each DSM option.
Table 6-12 Marketing, Recruitment, Incentive, and Development Costs (Washington)
DSM Option Annual Marketing/Recruitment
Cost Per Participant
Annual
Incentive Per
Participant
Program
Development
Cost

CTA-2045 Water Heating $67.50 $24.00 $75,000.00
DLC Smart Thermostats - Heating $67.50 $20.00 $23,963.15
DLC Smart Thermostats - Cooling $67.50 $20.00 $23,863.32
DLC Smart Appliances $50.00 $0.00 $24,084.70
Third Party Contracts $0.00 $0.00 $0.00

Time-of-Use Opt-in $57.50 $0.00 $12,315.14
Time-of-Use Opt-out $57.50 $0.00 $12,281.26
Variable Peak Pricing Rates $175.00 $0.00 $12,222.26
Thermal Energy Storage $100.00 $0.00 $14,994.78
Battery Energy Storage $25.00 $0.00 $8,017.36
Table 6-13 and Table 6-14 present the equivalent cost tables for the state of Idaho.
Table 6-13 DSM Program Operations Maintenance, and Equipment Costs (Idaho)
DSM Option Annual O&M Cost Per Participant Annual O&M
Cost per MW
Cost of Equip
+ Install Per
Participant
Cost of Equip
+ Install per
kW
DLC Central AC $13.00 $260.00 $0.00
DLC Water Heating $23.63 $472.50 $0.00
DLC Smart Thermostats – Heating $44.00 $0.00 $0.00
DLC Smart Thermostats - Cooling $44.00 $0.00 $0.00
DLC Smart Appliances $0.00 $300.00 $0.00
Third Party Contracts $0.00 $80,000.00 $0.00 $0.00

Time-of-Use Opt-in $0.00 $0.00 $0.00
Time-of-Use Opt-out $0.00 $0.00 $0.00
Variable Peak Pricing Rates $0.00 $0.00 $0.00
Thermal Energy Storage $308.00 $0.00 $6,160.00
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 942 of 1105
Battery Energy Storage $0.00 $27,897.60 $0.00
Behavioral $3.25 $0.00 $0.00

Table 6-14 Marketing, Recruitment, Incentive, and Development Costs (Idaho)
DSM Option
Annual
Marketing/Recruitmen
t Cost Per Participant
Annual Incentive Per
Participant
Program Development
Cost
DLC Central AC $67.50 $29.00 $13,636.68

DLC Smart
Thermostats - Heating $67.50 $20.00 $13,536.85
DLC Smart
Thermostats - Cooling $67.50 $20.00 $13,636.68

Third Party Contracts $0.00 $0.00 $0.00
DLC Electric Vehicle
Charging $50.00 $24.00 $25,864.40
Time-of-Use Opt-in $69.00 $0.00 $6,434.86
Time-of-Use Opt-out $69.00 $0.00 $6,468.74
Variable Peak Pricing
Rates $175.00 $0.00 $6,527.74
Thermal Energy
Storage $100.00 $0.00 $10,005.22
Battery Energy Storage $25.00 $0.00 $4,482.64
Behavioral $0.00 $0.00 $33,944.32

Other Cross-cutting Assumptions
In addition to the above program-specific assumptions, there are three that affect all programs:
• Discount rate. We used a nominal discount rate of 5.21% to calculate the net present value (NPV) of costs over the useful life of each DR program. All cost results are shown in nominal dollars.
• Line losses. Avista provided a line loss factor of 6.16% to convert estimated demand savings at the customer meter level to demand savings at the generator level. In the next section, we report our analysis results at the generator level.
• S hifting and Saving . Each program varies in the way energy is shifted or saved throughout the day. For example, customers on the DLC Central AC program are likely to pre-cool their homes prior to the event and turn their AC units back on after the event (snapback effect). The results in this report only show the savings during the event window and not before and after the event. However, shifting and savings assumptions were provided to Avista for each program to inform the IRP results.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 943 of 1105
DR Potential and Cost Estimates
This section presents analysis results on demand savings and cost estimates for DR programs. We developed savings estimates in two ways:
• First, we present the integrated results. If Avista offers more than one program, then the potential for double counting exists. To address this possibility, we created a participation hierarchy to define the order in which the programs are taken by customers. Then we computed the savings and costs under this scenario. For this study, we assumed a customer would not be on both a Central AC program and a Smart Thermostat program and would only be on a thermal energy storage program or battery energy storage program. The hierarchy of pricing rates is as follows: Time-of-Use, Variable Peak Pricing, and Real Time Pricing.
• At the very end of this section, we present high-level standalone results in 2045 without considering the integrated effects that occur if more than one DR option is offered to Avista customers. Standalone results represent an upper bound for each program individually and should not be added together as that would overstate the overall system level potential.
All potential results presented in this section represent capacity savings in terms of equivalent generation capacity.
Integrated Potential Results
The following sections separate out the integrated potential results for winter and summer for the Time-of-Use Opt-in and Time-of-Use Opt-out scenarios.
Winter TOU Opt-in Scenario
Figure 6-3 and Table 6-15 show the total winter demand savings from individual DR options for selected years of the analysis. These savings represent integrated savings from all available DR options in Avista’s Washington and Idaho service territories.
Key findings include:
• The highest potential option is CTA-2045 WH which is expected to reach a savings potential of 48.9 MW by 2045.
• The next three biggest potential options in winter include DLC Electric Vehicle Charging (30.2 MW in 2045), Third Part Contracts (21.9 MW), and Variable Peak Pricing Rates (12.0 MW)
• Since most of the participants are likely to be on the VPP pricing rate in the TOU Opt-in scenario, the TOU potential (4.1 MW in 2045) is significantly lower than in the Opt-out case (17.8 MW).
• The total potential savings in the winter TOU Opt-in scenario are expected to increase from 9.3 MW in 2022 to 144.3 MW by 2045. The respective increase in the percentage of system peak goes from 0.7% in 2022 to 10.0% by 2045.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 944 of 1105
Figure 6-3 Summary of Potential Analysis for Avista (TOU Opt-In Winter Peak MW @Generator)

Table 6-15 Achievable DR Potential by Option (TOU Opt-In Winter MW @Generator)
2022 2023 2025 2035 2045
Total System Peak (MW) 1,331 1,337 1,349 1,403 1,444
Market Potential (MW) 9.3 24.6 63.9 98.8 144.3
Market Potential (% of baseline) 0.7% 1.8% 4.7% 7.0% 10.0%
Achievable Potential (MW)
Battery Energy Storage 0.1 0.2 0.7 5.0 5.6
Behavioral 0.6 1.2 2.5 2.0 1.6
CTA-2045 WH 0.1 0.3 1.7 26.3 48.9
DLC Central AC - - - - -
DLC Smart Appliances 0.3 0.9 2.7 3.3 3.7
DLC Smart Thermostats - Cooling - - - - -
DLC Smart Thermostats - Heating 0.9 2.6 8.0 9.8 10.9
DLC Water Heating 0.5 1.6 4.9 5.5 5.5
Thermal Energy Storage - - - - -
Third Party Contracts 4.6 10.0 21.9 21.8 21.9
Time-of-Use Opt-in 0.5 1.8 5.3 4.9 4.1
-
20
40
60
80
100
120
140
160
2022 2023 2025 2035 2045
Ac
h
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v
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e

P
o
t
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n
t
i
a
l

(
M
W
)
Variable Peak PricingRatesTime-of-Use Opt-out
Time-of-Use Opt-in
Third Party Contracts
Thermal Energy Storage
DLC Water Heating
DLC Smart Thermostats -
HeatingDLC Smart Thermostats -
CoolingDLC Smart Appliances
DLC Electric Vehicle
ChargingDLC Central AC
CTA-2045 WH
Behavioral
Battery Energy Storage
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 945 of 1105
Time-of-Use Opt-out - - - - -
Variable Peak Pricing Rates 1.8 5.9 15.9 14.5 12.0
Achievable Potential (% of Baseline)
Battery Energy Storage 0.01% 0.02% 0.05% 0.36% 0.38%
Behavioral 0.04% 0.09% 0.18% 0.14% 0.11%
CTA-2045 WH 0.00% 0.02% 0.12% 1.88% 3.38%
DLC Central AC
DLC Electric Vehicle Charging 0.02% 0.40% 2.09%
DLC Smart Appliances 0.02% 0.07% 0.20% 0.24% 0.26%
DLC Smart Thermostats - Cooling
DLC Water Heating 0.04% 0.12% 0.37% 0.39% 0.38%
Thermal Energy Storage
Time-of-Use Opt-in 0.04% 0.13% 0.39% 0.35% 0.28%
Time-of-Use Opt-out
Variable Peak Pricing Rates 0.14% 0.44% 1.18% 1.03% 0.83%
Table 6-16 and Table 6-17 show demand savings by individual DR option for the states of Washington and Idaho separately. Using the available DSM options, Washington is projected to save 105.27 MW (7.2% of winter system peak demand) by 2045 while Idaho is projected to save 39.03 MW (2.67% of winter system peak demand) by 2045.
Table 6-16 Achievable DR Potential by Option for Washington (TOU Opt-In Winter MW @Generator)
2022 2023 2025 2035 2045
Total System Peak (MW) 1,331 1,337 1,349 1,403 1,463
Market Potential (MW) 6.91 16.53 39.46 69.22 105.27
Market Potential (% of System Peak) 0.5% 1.2% 2.9% 4.9% 7.2%
Battery Energy Storage 0.06 0.18 0.48 3.25 3.54
Behavioral 0.49 0.94 1.69 1.21 0.82
CTA-2045 WH 0.05 0.33 1.67 26.33 48.86
DLC Central AC - - - - -
DLC Smart Appliances 0.19 0.58 1.77 2.15 2.35
DLC Smart Thermostats - Cooling - - - - -
DLC Smart Thermostats - Heating 0.57 1.71 5.23 6.37 6.97
DLC Water Heating - - - - -
Thermal Energy Storage - - - - -
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 946 of 1105
Third Party Contracts 3.55 7.10 14.20 14.23 14.31
Time-of-Use Opt-in 0.46 1.34 3.57 3.07 2.32
Time-of-Use Opt-out - - - - -
Variable Peak Pricing Rates 1.54 4.36 10.66 8.96 6.63

Table 6-17 Achievable DR Potential by Option for Idaho (TOU Opt-In Winter MW @Generator)
2022 2023 2025 2035 2045
Total System Peak (MW) 1,331 1,337 1,349 1,403 1,463
Market Potential (MW) 2.43 8.09 24.43 29.63 39.03
Market Potential (% of System Peak) 0.18% 0.61% 1.81% 2.11% 2.67%
Achievable Potential (MW)
Battery Energy Storage 0.01 0.06 0.26 1.80 2.02
Behavioral 0.08 0.30 0.79 0.76 0.74
CTA-2045 WH - - - - -
DLC Electric Vehicle Charging - - 0.11 1.95 10.75
DLC Smart Appliances 0.10 0.31 0.95 1.19 1.35
DLC Smart Thermostats - Cooling - - - - -
DLC Smart Thermostats - Heating 0.29 0.89 2.74 3.44 3.89
DLC Water Heating 0.55 1.64 4.93 5.49 5.52
Third Party Contracts 1.02 2.93 7.69 7.60 7.58
Time-of-Use Opt-in 0.09 0.45 1.72 1.84 1.79
Time-of-Use Opt-out - - - - -
Variable Peak Pricing Rates 0.29 1.50 5.25 5.55 5.39
Cost Results
Table 6-18 presents the levelized costs per kW of equivalent generation capacity over 2022-2031 for both Washington and Idaho as well as the system weighted average levelized costs across both states. In addition, we show the 2031 savings potential from DR options for reference purposes.
Key findings include:
• The Third Party Contracts option delivers the highest savings in 2031 at approximately $75.26/kW-year cost. Capacity-based and energy-based payments to the third-party constitutes the major cost component for this option. All O&M and administrative costs are expected to be incurred by the representative third party contractor.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 947 of 1105
• The Variable Peak Pricing option has lowest levelized cost among all the DR options. It delivers 16.14 MW of savings in 2031 at $39.34/kW-year system wide. Enabling technology purchase and installation costs for enhancing customer response is a large part of CPP deployment costs.

Table 6-18 DR Program Costs and Potential (TOU Opt-In Winter)
DR Option WA ID System Wtd Avg Levelized
$/kW (2022-2031)
System Winter Potential
MW in Year 2031
Battery Energy Storage $833.17 $849.86 $839.87 2.81
Behavioral $158.42 $172.77 $161.07 2.26
CTA-2045 WH $174.13 $174.13 17.36
DLC Central AC -
DLC Electric Vehicle Charging $449.91 $452.04 $450.67 2.85
DLC Smart Appliances $398.04 $401.96 $399.70 3.21
DLC Smart Thermostats - Cooling -
DLC Smart Thermostats - Heating $76.79 $77.74 $77.19 9.42
DLC Water Heating $239.74 $239.74 5.48
Thermal Energy Storage -
Time-of-Use Opt-in $78.12 $97.73 $84.82 5.46
Time-of-Use Opt-out -
Variable Peak Pricing Rates $38.26 $40.90 $39.34 16.14

Winter TOU Opt-out Scenario
Figure 6-4 and Table 6-19 show the total winter demand savings from individual DR options for selected years of the analysis. These savings represent integrated savings from all available DR options in Avista’s Washington and Idaho service territories.
Key findings include:
• Once again the largest potential is in CTA-2045 WH, at 48.9 MW by 2045.
• After CTA-2045 WH, the next three biggest potential options in winter include DLC Electric Vehicle Charging (30.2 MW in 2045), Third Party Contracts (21.9 MW), and TOU (17.8 MW).
• In the TOU opt-out scenario, customers are placed on the Time-of-Use rate by default and will need to go through an added step to switch rates. Therefore, the majority of savings among the rates are concentrated in TOU which is expected to reach 17.8 MW by 2045.
• In the Opt-out scenario, most of the participants are likely to be on the TOU pricing rate and we see a much lower savings potential for the VPP rate (4.0 MW by 2045).
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 948 of 1105
• The total potential savings in the winter TOU Opt-out scenario are expected to increase from 36.4 MW in 2022 to 150.1 MW by 2045. The respective increase in the percentage of system peak increases from 2.7% in 2022 to 10.4% by 2045.
Figure 6-4 Summary of Winter Potential Analysis for Avista (TOU Opt-Out MW @Generator)

Table 6-19 Achievable DR Potential by Option – TOU Opt-Out (Winter MW @Generator)
2022 2023 2025 2035 2045
Total System Peak (MW) 1,331 1,337 1,349 1,403 1,444
Market Potential (MW) 36.4 45.3 71.1 104.5 150.1
Market Potential (% of baseline) 2.7% 3.4% 5.3% 7.4% 10.4%
Potential Forecast 1,294 1,291 1,278 1,299 1,294

Behavioral 0.6 1.3 2.5 2.1 1.7
CTA-2045 WH 0.1 0.3 1.7 26.3 48.9
DLC Central AC - - - - -
DLC Electric Vehicle Charging - - 0.3 5.6 30.2
DLC Smart Appliances 0.3 0.9 2.7 3.3 3.7
-
20
40
60
80
100
120
140
160
2022 2023 2025 2035 2045
Ac
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(
M
W
)
Variable Peak Pricing Rates
Time-of-Use Opt-out
Time-of-Use Opt-in
Third Party Contracts
Thermal Energy Storage
DLC Water Heating
DLC Smart Thermostats -
HeatingDLC Smart Thermostats -CoolingDLC Smart Appliances
DLC Electric Vehicle Charging
DLC Central AC
CTA-2045 WH
Behavioral
Battery Energy Storage
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 949 of 1105
DLC Smart Thermostats - Cooling - - - - -
DLC Smart Thermostats - Heating 0.9 2.6 8.0 9.8 10.9
DLC Water Heating 0.5 1.6 4.9 5.5 5.5
Thermal Energy Storage - - - - -
Third Party Contracts 4.6 10.0 21.9 21.8 21.9
Time-of-Use Opt-in - - - - -
Time-of-Use Opt-out 29.3 27.0 23.7 20.3 17.8
Variable Peak Pricing Rates 0.2 1.3 4.6 4.7 4.0
Achievable Potential (% of Baseline)
Battery Energy Storage 0.01% 0.02% 0.05% 0.36% 0.38%
CTA-2045 WH 0.00% 0.02% 0.12% 1.88% 3.38%
DLC Central AC
DLC Electric Vehicle Charging 0.02% 0.40% 2.09%
DLC Smart Appliances 0.02% 0.07% 0.20% 0.24% 0.26%
DLC Smart Thermostats - Heating 0.06% 0.19% 0.59% 0.70% 0.75%
DLC Water Heating 0.04% 0.12% 0.37% 0.39% 0.38%
Thermal Energy Storage
Third Party Contracts 0.34% 0.75% 1.62% 1.56% 1.52%
Time-of-Use Opt-in
Variable Peak Pricing Rates 0.01% 0.10% 0.34% 0.33% 0.28%

Table 6-20 and Table 6-21 show demand savings by individual DR option for the states of Washington and Idaho separately.
Table 6-20 Achievable DR Potential by Option for Washington - TOU Opt-Out (MW @Generator)
2022 2023 2025 2035 2045
Total System Peak (MW) 1,331 1,337 1,349 1,403 1,463
Market Potential (MW) 29.20 31.62 44.49 73.31 109.61
Market Potential (% of System Peak) 2.2% 2.4% 3.3% 5.2% 7.5%
Achievable Potential (MW)
Battery Energy Storage 0.06 0.18 0.48 3.25 3.54
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 950 of 1105
CTA-2045 WH 0.05 0.33 1.67 26.33 48.86
DLC Central AC - - - - -
DLC Electric Vehicle Charging - - 0.20 3.65 19.47
DLC Smart Appliances 0.19 0.58 1.77 2.15 2.35
DLC Smart Thermostats - Cooling - - - - -
DLC Smart Thermostats - Heating 0.57 1.71 5.23 6.37 6.97
DLC Water Heating - - - - -
Thermal Energy Storage - - - - -
Time-of-Use Opt-out 24.29 20.07 16.07 13.05 10.79
Variable Peak Pricing Rates 0.02 0.71 3.13 2.95 2.32

Table 6-21 Achievable DR Potential by Option for Idaho – TOU Opt-Out (MW @Generator)
2022 2023 2025 2035 2045
Market Potential (% of System Peak) 0.54% 1.03% 1.97% 2.22% 2.77%
Achievable Potential (MW)
Battery Energy Storage 0.01 0.06 0.26 1.80 2.02
Behavioral 0.08 0.30 0.79 0.76 0.74
CTA-2045 WH - - - - -
DLC Electric Vehicle Charging - - 0.11 1.95 10.75
DLC Smart Appliances 0.10 0.31 0.95 1.19 1.35
DLC Smart Thermostats - Cooling - - - - -
DLC Smart Thermostats - Heating 0.29 0.89 2.74 3.44 3.89
DLC Water Heating 0.55 1.64 4.93 5.49 5.52
Thermal Energy Storage - - - - -
Time-of-Use Opt-out 5.00 6.93 7.62 7.20 6.99
Variable Peak Pricing Rates 0.16 0.64 1.49 1.70 1.66
Cost Results
Table 6-22 presents the levelized costs per kW of equivalent generation capacity over 2022-2031 for both Washington and Idaho as well as the system weighted average levelized costs across both states. In addition, we show the 2031 savings potential from DR options for reference purposes.
Key findings include:
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 951 of 1105
• The Third Party Contracts option delivers the highest savings potential of 21.83 MW in 2031 at approximately $75.26/kW-year cost. Capacity-based and energy-based payments to the third-party constitutes the major cost component for this option. All O&M and administrative costs are expected to be incurred by the representative third party contractor.
• The TOU Opt-out option has the second highest potential to contribute 21.34 MW of savings in 2031 at approximately $99.84/kW-year
• The Variable Peak Pricing option has lowest levelized cost among all the DR options. It delivers 4.95 MW of savings in 2031 at $59.11/kW-year system wide. Enabling technology purchase and installation costs for enhancing customer response is a large part of VPP deployment costs.

Table 6-22 DR Program Costs and Potential – TOU Opt Out Winter
DR Option WA ID System Wtd Avg Levelized
$/kW (2022-2031)
System Winter Potential
MW in Year 2031
Battery Energy Storage $833.17 $849.86 $839.87 2.81
Behavioral $154.99 $172.77 $172.77 2.26
CTA-2045 WH $174.13 $174.13 17.36
DLC Central AC -
DLC Electric Vehicle Charging $449.91 $452.04 $450.67 2.85
DLC Smart Appliances $398.04 $401.96 $399.70 3.21
DLC Smart Thermostats - Cooling -
DLC Smart Thermostats - Heating $76.79 $77.74 $77.19 9.42
DLC Water Heating $239.74 $239.74 5.48
Thermal Energy Storage -
Third Party Contracts $75.36 $75.07 $75.26 21.83
Time-of-Use Opt-in -
Time-of-Use Opt-out $97.99 $103.41 $99.84 21.34
Variable Peak Pricing Rates $58.72 $59.77 $59.11 4.95

Summer TOU Opt-in Scenario
Figure 6-5 and Table 6-23 show the total summer demand savings from individual DR options for selected years of the analysis. These savings represent integrated savings from all available DR options in Avista’s Washington and Idaho service territories.
Key findings include:
• The highest potential option is DLC Smart Thermostats, which is expected to reach savings potential of 61 MW by 2045.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 952 of 1105
• The next two biggest potential options in summer include CTA-2045 WH (48.9 MW in 2045), DLC Electric Vehicle Charging (30.2 MW), and DLC Central AC (24.5 MW).
• Two Space cooling options- DLC Smart Thermostat and DLC Central AC – are expected to contribute a combined 85.5 MW by 2045.
• Total potential savings in the summer TOU Opt-in scenario are expected to increase from 11.3 MW in 2022 to 232 MW by 2045. The respective increase in the percentage of system peak increases from 0.8% in 2022 to 15.4% by 2045.
Figure 6-5 Summary of Summer Potential by Option (TOU Opt-In MW @Generator)

Table 6-23 Achievable DR Potential by Option TOU Opt-In (Summer MW @Generator)
2022 2023 2025 2035 2045
Total System Peak (MW) 1,369 1,376 1,389 1,446 1,508
Market Potential (MW) 11.3 31.3 86.8 151.9 232.0
Market Potential (% of baseline) 0.8% 2.3% 6.3% 10.5% 15.4%
Potential Forecast 1,358 1,344 1,302 1,294 1,276
Achievable Potential (MW)
Battery Energy Storage 0.1 0.2 0.7 5.0 5.6
Behavioral 0.6 1.3 2.6 2.1 1.7
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CTA-2045 WH
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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 953 of 1105
CTA-2045 WH 0.1 0.3 1.7 26.3 48.9
DLC Central AC 0.8 2.5 8.1 16.2 24.5
DLC Electric Vehicle Charging - - 0.3 5.6 30.2
DLC Smart Appliances 0.3 0.9 2.7 3.3 3.7
DLC Smart Thermostats - Cooling 1.6 5.1 17.4 37.4 61.0
DLC Smart Thermostats - Heating - - - - -
DLC Water Heating 1.0 2.9 9.1 13.7 17.8
Thermal Energy Storage 0.1 0.2 0.6 0.7 0.6
Third Party Contracts 4.5 9.8 21.4 21.3 21.4
Time-of-Use Opt-in 0.6 1.9 5.5 5.1 4.3
Variable Peak Pricing Rates 1.9 6.1 16.7 15.1 12.5
Achievable Potential (% of Baseline)
Battery Energy Storage 0.01% 0.02% 0.05% 0.36% 0.38%
Behavioral 0.04% 0.09% 0.18% 0.14% 0.11%
DLC Central AC 0.06% 0.18% 0.58% 1.12% 1.62%
DLC Electric Vehicle Charging 0.02% 0.39% 2.00%
DLC Smart Appliances 0.02% 0.06% 0.20% 0.23% 0.25%
DLC Smart Thermostats - Cooling 0.12% 0.37% 1.25% 2.58% 4.04%
DLC Smart Thermostats - Heating
Thermal Energy Storage 0.00% 0.01% 0.05% 0.05% 0.04%
Third Party Contracts 0.33% 0.71% 1.54% 1.48% 1.42%
Time-of-Use Opt-in 0.04% 0.14% 0.40% 0.35% 0.28%
Time-of-Use Opt-out
Variable Peak Pricing Rates 0.14% 0.45% 1.20% 1.05% 0.83%

Table 6-24 and Table 6-25 show demand savings by individual DR option for the states of Washington and Idaho separately.
Table 6-24 Achievable DR Potential by Option for Washington TOU Opt-In (Summer MW @Generator)
2022 2023 2025 2035 2045
Total System Peak (MW) 1,369 1,376 1,389 1,446 1,508
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 954 of 1105
Market Potential (MW) 8.37 21.28 55.63 105.72 164.59
Market Potential (% of System Peak) 0.6% 1.5% 4.0% 7.3% 10.9%
Achievable Potential (MW)
Battery Energy Storage 0.06 0.18 0.48 3.25 3.54
Behavioral 0.52 1.02 1.81 1.31 0.88
CTA-2045 WH 0.05 0.33 1.67 26.33 48.86
DLC Central AC 0.50 1.59 5.18 10.25 15.34
DLC Electric Vehicle Charging - - 0.20 3.65 19.47
DLC Smart Appliances 0.19 0.58 1.77 2.15 2.35
DLC Smart Thermostats - Cooling 1.02 3.25 11.12 23.68 38.26
DLC Water Heating 0.40 1.28 4.15 8.20 12.26
Thermal Energy Storage 0.05 0.13 0.39 0.40 0.36
Third Party Contracts 3.46 6.92 13.84 13.88 13.96
Time-of-Use Opt-in 0.49 1.41 3.76 3.22 2.41
Variable Peak Pricing Rates 1.63 4.60 11.26 9.41 6.91

Table 6-25 Achievable DR Potential by Option for Idaho TOU Opt-In (Summer MW @Generator)
2022 2023 2025 2035 2045
Total System Peak (MW) 1,369 1,376 1,389 1,446 1,508
Market Potential (% of System Peak) 0.22% 0.72% 2.25% 3.20% 4.47%
Battery Energy Storage 0.01 0.06 0.26 1.80 2.02
Behavioral 0.08 0.31 0.83 0.80 0.78
CTA-2045 WH - - - - -
DLC Central AC 0.28 0.89 2.90 5.92 9.11
DLC Electric Vehicle Charging - - 0.11 1.95 10.75
DLC Smart Appliances 0.10 0.31 0.95 1.19 1.35
DLC Smart Thermostats - Cooling 0.56 1.81 6.24 13.67 22.72
DLC Smart Thermostats - Heating - - - - -
DLC Water Heating 0.55 1.64 4.93 5.49 5.52
Thermal Energy Storage 0.01 0.06 0.24 0.27 0.27
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 955 of 1105
Third Party Contracts 1.00 2.88 7.55 7.47 7.46
Time-of-Use Opt-in 0.09 0.46 1.77 1.90 1.85
Time-of-Use Opt-out - - - - -
Variable Peak Pricing Rates 0.30 1.55 5.42 5.73 5.57
Cost Results
Table 6-26 presents the levelized costs per kW of equivalent generation capacity over 2022-2031 for both Washington and Idaho as well as the system weighted average levelized costs across both states. In addition, we show the 2031 savings potential from DR options for reference purposes.
Key findings include:
• DLC Smart Thermostats deliver the highest savings in 2031 (28.68 MW) at approximately $127.27/kW-year cost. Capacity-based and energy-based payments to the third-party constitutes the major cost component for this option. All O&M and administrative costs are expected to be incurred by the representative third party contractor.
• The Variable Peak Pricing option has the lowest levelized cost among all the DR options. It delivers 16.89 MW of savings in 2031 at $37.51/kW-year system wide. Enabling technology purchase and installation costs for enhancing customer response is a large part of CPP deployment costs.
Table 6-26 DR Program Costs and Potential – Summer TOU Opt-In
DR Option WA ID System Wtd Avg Levelized
$/kW (2022-2031)
System Summer Potential
MW in Year 2031
Behavioral $143.96 $164.86 $151.82 2.41
CTA-2045 WH $174.13 $174.13 17.36
DLC Central AC $161.09 $156.97 $159.34 12.80
DLC Electric Vehicle Charging $449.91 $452.04 $450.67 2.85
DLC Smart Appliances $398.04 $401.96 $399.70 3.21
DLC Smart Thermostats - Heating -
DLC Water Heating $239.74 $239.74 5.48
Thermal Energy Storage $1,000.92 $957.45 $983.76 0.68
Third Party Contracts $77.29 $76.39 $76.97 21.35
Time-of-Use Opt-in $74.13 $94.63 $81.21 5.71
Variable Peak Pricing Rates $36.25 $39.64 $37.51 16.89

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 956 of 1105
Summer TOU Opt-out Scenario
Figure 6-6 and Table 6-27 show the total summer demand savings from individual DR options for selected years of the analysis. These savings represent integrated savings from all available DR options in Avista’s Washington and Idaho service territories.
Key findings include:
• Once again the highest savings potential resides in DLC Smart Thermostats, increasing from 1.6 MW in 2022 to 61.0 MW in 2045.
• The next two biggest potential options in Summer include CTA-2045 WH (48.9 MW by 2045), DLC Electric Vehicle Charging (30.2 MW), and DLC Central AC (24.5 MW). DLC Smart Thermostat and DLC Central AC options together contribute 85.5 MW of potential by 2045.
• In the TOU opt-out scenario, customers are placed on the Time-of-Use rate by default and will need to go through an added step to switch rates. Therefore, the majority of savings among the rates are concentrated in TOU which is expected to reach 18.3 MW by 2045.
• In the Opt-out scenario, most of the participants are likely to be on the TOU pricing rate and we see a much lower savings potential for the VPP rate (4.1 MW by 2045).
• The total potential savings in the summer TOU Opt-in scenario are expected to increase from 39.0 MW in 2022 to 225.6 MW by 2045. The respective increase in the percentage of system peak goes from 2.8% in 2022 to 15.0% by 2045.

Figure 6-6 Summary of Summer Potential – TOU Opt-Out (MW @Generator)

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DLC Electric VehicleChargingDLC Central AC
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 957 of 1105

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 958 of 1105
Table 6-27 Achievable DR Potential by Option – TOU Opt-Out (Summer MW @Generator)
2022 2023 2025 2035 2045
Total System Peak (MW) 1,369 1,376 1,389 1,446 1,508
Market Potential (% of baseline) 2.8% 3.7% 6.5% 10.3% 15.0%
Potential Forecast 1,330 1,324 1,299 1,296 1,282
Achievable Potential (MW)
Battery Energy Storage 0.1 0.2 0.7 5.0 5.6
CTA-2045 WH 0.1 0.3 1.7 26.3 48.9
DLC Central AC 0.8 2.5 8.1 16.2 24.5
DLC Electric Vehicle Charging - - 0.3 5.6 30.2
DLC Smart Appliances 0.3 0.9 2.7 3.3 3.7
DLC Smart Thermostats - Cooling 1.6 5.1 17.4 37.4 61.0
DLC Water Heating 0.5 1.6 4.9 5.5 5.5
Thermal Energy Storage 0.1 0.2 0.6 0.7 0.6
Third Party Contracts 4.5 9.8 21.4 21.3 21.4
Time-of-Use Opt-in - - - - -
Time-of-Use Opt-out 30.4 28.0 24.6 20.9 18.3
Variable Peak Pricing Rates 0.2 1.4 4.8 4.9 4.1
Achievable Potential (% of Baseline)
Behavioral 0.04% 0.09% 0.19% 0.15% 0.12%
CTA-2045 WH 0.00% 0.02% 0.12% 1.82% 3.24%
DLC Central AC 0.06% 0.18% 0.58% 1.12% 1.62%
DLC Electric Vehicle Charging 0.02% 0.39% 2.00%
DLC Smart Appliances 0.02% 0.06% 0.20% 0.23% 0.25%
DLC Smart Thermostats - Heating
DLC Water Heating 0.04% 0.12% 0.35% 0.38% 0.37%
Thermal Energy Storage 0.00% 0.01% 0.05% 0.05% 0.04%
Third Party Contracts 0.33% 0.71% 1.54% 1.48% 1.42%
Time-of-Use Opt-in
Time-of-Use Opt-out 2.22% 2.04% 1.77% 1.45% 1.21%
Variable Peak Pricing Rates 0.01% 0.10% 0.35% 0.34% 0.27%

Table 6-28 and Table 6-29 show demand savings by individual DR option for the states of Washington and Idaho separately.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 959 of 1105
Table 6-28 Achievable DR Potential by Option for Washington – TOU Opt-Out (Summer MW @Generator)
2022 2023 2025 2035 2045
Total System Peak (MW) 1,369 1,376 1,389 1,446 1,508
Market Potential (MW) 31.19 35.70 56.62 101.68 156.75
Battery Energy Storage 0.06 0.18 0.48 3.25 3.54
Behavioral 0.53 1.03 1.88 1.44 1.06
CTA-2045 WH 0.05 0.33 1.67 26.33 48.86
DLC Central AC 0.50 1.59 5.18 10.25 15.34
DLC Electric Vehicle Charging - - 0.20 3.65 19.47
DLC Smart Appliances 0.19 0.58 1.77 2.15 2.35
DLC Smart Thermostats - Cooling 1.02 3.25 11.12 23.68 38.26
DLC Smart Thermostats - Heating - - - - -
DLC Water Heating - - - - -
Thermal Energy Storage 0.05 0.13 0.39 0.40 0.36
Third Party Contracts 3.46 6.92 13.84 13.88 13.96
Time-of-Use Opt-in - - - - -
Time-of-Use Opt-out 25.32 20.94 16.79 13.55 11.12
Variable Peak Pricing Rates 0.02 0.75 3.30 3.11 2.43

Table 6-29 Achievable DR Potential by Option for Idaho – TOU Opt-Out (Summer MW @Generator)
2022 2023 2025 2035 2045
Market Potential (% of System Peak) 0.57% 1.14% 2.40% 3.30% 4.57%
Achievable Potential (MW)
Battery Energy Storage 0.01 0.06 0.26 1.80 2.02
Behavioral 0.08 0.31 0.83 0.80 0.78
DLC Central AC 0.28 0.89 2.90 5.92 9.11
DLC Electric Vehicle Charging - - 0.11 1.95 10.75
DLC Smart Appliances 0.10 0.31 0.95 1.19 1.35
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 960 of 1105
DLC Smart Thermostats - Cooling 0.56 1.81 6.24 13.67 22.72
DLC Smart Thermostats - Heating - - - - -
DLC Water Heating 0.55 1.64 4.93 5.49 5.52
Thermal Energy Storage 0.01 0.06 0.24 0.27 0.27
Third Party Contracts 1.00 2.88 7.55 7.47 7.46
Time-of-Use Opt-in - - - - -
Time-of-Use Opt-out 5.07 7.08 7.82 7.39 7.18
Variable Peak Pricing Rates 0.17 0.67 1.54 1.76 1.71
Cost Results
Table 6-30 presents the levelized costs per kW of equivalent generation capacity over 2022-2031 for both Washington and Idaho as well as the system weighted average levelized costs across both states. In addition, we show the 2031 savings potential from DR options for reference purposes.
Key findings include:
• DLC Smart Thermosts delivers the highest savings potential in 2031 (28.68 MW) at approximately $127.27/kW-year cost. Capacity-based and energy-based payments to the third-party constitutes the major cost component for this option. All O&M and administrative costs are expected to be incurred by the representative third party contractor.
• The Variable Peak Pricing option has the lowest levelized cost among all the DR options. It delivers 5.18 MW of savings in 2031 at $56.48/kW-year system wide. Enabling technology purchase and installation costs for enhancing customer response is a large part of CPP deployment costs.

Table 6-30 DR Program Costs and Potential – Summer TOU Opt-Out
DR Option WA ID System Wtd Avg Levelized
$/kW (2022-2031)
System Summer Potential
MW in Year 2031
Battery Energy Storage $833.17 $849.86 $839.87 2.81
Behavioral $143.96 $164.86 $151.02 2.41
CTA-2045 WH $174.13 $174.13 17.36
DLC Central AC $161.09 $156.97 $159.34 12.80
DLC Electric Vehicle Charging $449.91 $452.04 $450.67 2.85
DLC Smart Appliances $398.04 $401.96 $399.70 3.21
DLC Smart Thermostats - Cooling $129.24 $124.60 $127.27 28.68
DLC Smart Thermostats - Heating -
Thermal Energy Storage $1,000.92 $957.45 $983.76 0.68
Third Party Contracts $77.29 $76.39 $76.97 21.35
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 961 of 1105
Time-of-Use Opt-in
Time-of-Use Opt-out $93.94 $100.94 $96.35 22.10
Variable Peak Pricing Rates $55.64 $57.91 $56.48 5.18

Stand-alone Potential Results
The above results assume that the programs are offered on an integrated basis where participation across similar options do not overlap. However, it is also important to see the potential by option where each program is unaffected by participation in other options. This way, Avista can gauge the impact from implementing an individual program. For this scenario we do not combine the potential savings and only show individual potential contributions by program for each scenario.
Winter Results
Figure 6-7 and Table 6-31 show the winter demand savings from individual DR options for selected years of the analysis. These savings represent stand-alone savings from all available DR options in Avista’s Washington and Idaho service territories.
Key findings include:
• The largest savings potential resides in CTA-2045 WH, contributing 0.1 MW of potential in 2022 and increasing to 48.9 MW by 2045.
• The next biggest option is DLC Electric Vehicle Charging, at 30.2 MW of potential by 2045.
• When each TOU option is examined as an individual program, the Time-of-Use Opt-out option has a much larger potential savings then if participants could opt-in to the rate. The TOU Opt-out option is expected to reach 29.9 MW by 2045 in the stand-alone case.
• Since the different rate options do not influence other rates in the stand-alone scenario, each rate has a larger potential savings than in the Opt-out/Opt-in scenarios.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 962 of 1105
Figure 6-8 Summary of Potential Analysis for Avista (Winter Peak MW @Generator)

Table 6-32 Achievable DR Potential by Option (Winter MW @Generator)
2022 2023 2025 2035 2045
Total System Peak (MW) 1,331 1,337 1,349 1,403 1,444
Market Potential (MW) 39.5 54.2 100.2 142.6
194.5
Market Potential (% of baseline) 3.0% 4.1% 7.4% 10.2% 13.5%
Potential Forecast 1,291 1,282 1,249 1,261 1,250
Achievable Potential (MW)
Battery Energy Storage 0.1 0.2 0.7 5.0 5.6
Behavioral 0.6 1.3 3.0 3.1 3.3
CTA-2045 WH 0.1 0.3 1.7 26.3 48.9
DLC Central AC - - - - -
DLC Electric Vehicle Charging - - 0.3 5.6 30.2
DLC Smart Appliances 0.3 0.9 2.7 3.3 3.7
DLC Smart Thermostats - Cooling - - - - -
DLC Smart Thermostats - Heating 0.9 2.6 8.0 9.8 10.9
DLC Water Heating 0.5 1.6 4.9 5.5 5.5
Thermal Energy Storage - - - - -
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ChargingDLC Central AC
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 963 of 1105
Third Party Contracts 4.6 10.0 21.9 21.8 21.9
Time-of-Use Opt-in 0.6 1.9 6.4 7.5 7.8
Variable Peak Pricing Rates 1.9 6.5 22.0 25.7 26.9
Achievable Potential (% of Baseline)
Battery Energy Storage 0.01% 0.02% 0.05% 0.36% 0.39%
Behavioral 0.04% 0.10% 0.22% 0.22% 0.23%
CTA-2045 WH 0.00% 0.02% 0.12% 1.88% 3.38%
DLC Central AC
DLC Electric Vehicle Charging 0.02% 0.40% 2.09%
DLC Smart Thermostats - Cooling
DLC Smart Thermostats - Heating 0.06% 0.19% 0.59% 0.70% 0.75%
Thermal Energy Storage
Third Party Contracts 0.34% 0.75% 1.62% 1.56% 1.52%
Time-of-Use Opt-in 0.04% 0.14% 0.48% 0.53% 0.54%
Time-of-Use Opt-out 2.26% 2.16% 2.11% 2.06% 2.07%
Variable Peak Pricing Rates 0.14% 0.49% 1.63% 1.83% 1.86%

Table 6-33 and Table 6-34 show demand savings by individual DR option for the states of Washington and Idaho separately.
Table 6-33 Achievable DR Potential by Option for Washington (Winter MW @Generator)
2022 2023 2025 2035 2045
Total System Peak (MW) 1,331 1,337 1,349 1,403 1,463
Market Potential (MW)
31.90
38.50
63.59

99.07

140.00
Market Potential (% of System Peak) 2.4% 2.9% 4.7% 7.1% 9.6%
Achievable Potential (MW)
Battery Energy Storage 0.06 0.18 0.48 3.25 3.54
Behavioral 0.49 0.99 2.01 2.10 2.18
CTA-2045 WH 0.05 0.33 1.67 26.33 48.86
DLC Electric Vehicle Charging - - 0.20 3.65 19.47
DLC Smart Appliances 0.19 0.58 1.77 2.15 2.35
DLC Smart Thermostats - Cooling - - - - -
DLC Smart Thermostats - Heating 0.57 1.71 5.23 6.37 6.97
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 964 of 1105
DLC Water Heating - - - - -
Thermal Energy Storage - - - - -
Third Party Contracts 3.55 7.10 4.20 14.23 14.31
Time-of-Use Opt-in 0.47 1.43 4.32 4.95 5.11
Time-of-Use Opt-out 24.92 21.36 19.07 19.18 19.71
Variable Peak Pricing Rates 1.60 4.83 14.65 16.88 17.49

Table 6-34 Achievable DR Potential by Option for Idaho (Winter MW @Generator)
2022 2023 2025 2035 2045
Total System Peak (MW) 1,331 1,337 1,349 1,403 1,463
Market Potential (MW) 7.59 15.74
36.63 43.52 54.53
Market Potential (% of System Peak) 0.57% 1.18% 2.71% 3.10% 3.73%
Battery Energy Storage 0.01 0.06 0.26 1.80 2.02
Behavioral 0.08 0.31 0.97 1.05 1.14
CTA-2045 WH - - - - -
DLC Central AC - - - - -
DLC Electric Vehicle Charging - - 0.11 1.95 10.75
DLC Smart Appliances 0.10 0.31 0.95 1.19 1.35
DLC Smart Thermostats - Cooling - - - - -
DLC Smart Thermostats - Heating 0.29 0.89 2.74 3.44 3.89
DLC Water Heating 0.55 1.64 4.93 5.49 5.52
Thermal Energy Storage - - - - -
Third Party Contracts 1.02 2.93 7.69 7.60 7.58
Time-of-Use Opt-in 0.09 0.48 2.12 2.50 2.66
Time-of-Use Opt-out 5.15 7.45 9.46 9.70 10.22
Summer Results
Figure 6-9 and Table 6-36 show the summer demand savings from individual DR options for selected years of the analysis. These savings represent the individual stand-alone savings from all available DR options in Avista’s Washington and Idaho service territories.
Key findings include:
• The largest potential option is DLC Smart thermostats, at 61.0 MW by 2045.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 965 of 1105
• The next two biggest potential options in summer include CTA-2045 WH and TOU Opt-out, each of which are projected to contribute over 30 MW by 2045. DLC Central AC and DLC Electric Vehicle Charging also have high savings potential by 2045.
• When each TOU option is examined as an individual program, the Time-of-Use Opt-out option has a much larger potential savings then if participants could opt-in to the rate. The TOU Opt-out option makes up the second-largest savings potential in the stand-alone case and is expected to reach 31.1 MW by 2045.
• Since the different rate options do not influence other rates in the stand-alone scenario, each rate has a larger potential savings than in the Opt-out/Opt-in scenarios.
Figure 6-9 Summary of Summer Potential by Option (MW @Generator)

Table 6-35 Achievable DR Potential by Option (Summer MW @Generator)
2022 2023 2025 2035 2045
Total System Peak (MW) 1,369 1,376 1,389 1,446 1,508
Market Potential (% of baseline) 3.1% 4.5% 9.0% 13.9% 19.5%
Potential Forecast 1,327 1,314 1,264 1,244 1,214
Battery Energy Storage 0.1 0.2 0.7 5.0 5.6
Behavioral 0.6 1.4 3.2 3.4 3.5
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Variable Peak PricingRatesTime-of-Use Opt-out
Time-of-Use Opt-in
Third Party Contracts
Thermal Energy Storage
DLC Water Heating
DLC Smart Thermostats
- HeatingDLC Smart Thermostats
- CoolingDLC Smart Appliances
DLC Electric Vehicle
ChargingDLC Central AC
CTA-2045 WH
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 966 of 1105
DLC Central AC 0.8 2.5 8.7 18.7 30.5
DLC Electric Vehicle Charging - - 0.3 5.6 30.2
DLC Smart Thermostats - Cooling 1.6 5.1 17.4 37.4 61.0
DLC Smart Thermostats - Heating - - - - -
DLC Water Heating 1.0 2.9 9.4 15.0 20.8
Thermal Energy Storage 0.1 0.2 0.7 0.8 0.8
Third Party Contracts 4.5 9.8 21.4 21.3 21.4
Time-of-Use Opt-in 0.6 2.0 6.7 7.8 8.1
Time-of-Use Opt-out 31.2 29.9 29.6 30.0 31.1
Achievable Potential (% of Baseline)
Battery Energy Storage 0.01% 0.02% 0.05% 0.36% 0.39%
CTA-2045 WH 0.00% 0.02% 0.12% 1.82% 3.24%
DLC Central AC 0.06% 0.18% 0.62% 1.29% 2.02%
DLC Electric Vehicle Charging 0.02% 0.39% 2.00%
DLC Smart Appliances 0.02% 0.06% 0.20% 0.23% 0.25%
DLC Smart Thermostats - Cooling 0.12% 0.37% 1.25% 2.58% 4.04%
DLC Smart Thermostats - Heating
DLC Water Heating 0.07% 0.21% 0.68% 1.04% 1.38%
Thermal Energy Storage 0.00% 0.01% 0.05% 0.05% 0.06%
Third Party Contracts 0.33% 0.71% 1.54% 1.48% 1.42%
Time-of-Use Opt-in 0.04% 0.15% 0.49% 0.54% 0.54%
Time-of-Use Opt-out 2.28% 2.17% 2.13% 2.07% 2.06%
Variable Peak Pricing Rates 0.15% 0.49% 1.66% 1.86% 1.87%

Table 6-37 and Table 6-38 show summer demand savings by individual DR option for the states of Washington and Idaho separately. The programs with the largest potential savings are CTA-2045 WH, DLC Smart Thermostat, and TOU rates.
Table 6-36 Achievable DR Potential by Option for Washington (Summer MW @Generator)
2022 2023 2025 2035 2045
Total System Peak (MW) 1,369 1,376 1,389 1,446 1,508
Market Potential (MW) 34.41 44.24 81.54 140.01 208.12
Market Potential (% of System Peak) 2.5% 3.2% 5.9% 9.7% 13.8%
Achievable Potential (MW)
Battery Energy Storage 0.06 0.18 0.48 3.25 3.54
Behavioral 0.53 1.07 2.17 2.26 2.35
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 967 of 1105
CTA-2045 WH 0.05 0.33 1.67 26.33 48.86
DLC Central AC 0.51 1.63 5.56 11.84 19.13
DLC Electric Vehicle Charging - - 0.20 3.65 19.47
DLC Smart Appliances 0.19 0.58 1.77 2.15 2.35
DLC Smart Thermostats - Cooling 1.02 3.25 11.12 23.68 38.26
DLC Smart Thermostats - Heating - - - - -
DLC Water Heating 0.41 1.30 4.45 9.47 15.28
Thermal Energy Storage 0.05 0.14 0.41 0.48 0.50
Third Party Contracts 3.46 6.92 13.84 13.88 13.96
Time-of-Use Opt-in 0.50 1.50 4.55 5.22 5.39
Variable Peak Pricing Rates 1.69 5.09 15.45 17.80 18.46

Table 6-37 Achievable DR Potential by Option for Idaho (Summer MW @Generator)
2022 2023 2025 2035 2045
Total System Peak (MW) 1,369 1,376 1,389 1,446 1,508
Market Potential (MW) 8.21 17.81
43.96 61.44 85.68
Market Potential (% of System Peak) 0.60% 1.29% 3.17% 4.25% 5.68%
Achievable Potential (MW)
Battery Energy Storage 0.01 0.06 0.26 1.80 2.02
Behavioral 0.08 0.33 1.02 1.10 1.20
CTA-2045 WH - - - - -
DLC Central AC 0.28 0.91 3.12 6.84 11.36
DLC Electric Vehicle Charging - - 0.11 1.95 10.75
DLC Smart Appliances 0.10 0.31 0.95 1.19 1.35
DLC Smart Thermostats - Cooling 0.56 1.81 6.24 13.67 22.72
DLC Water Heating 0.55 1.64 4.93 5.49 5.52
Thermal Energy Storage 0.01 0.06 0.26 0.31 0.33
Third Party Contracts 1.00 2.88 7.55 7.47 7.46
Time-of-Use Opt-in 0.09 0.50 2.19 2.59 2.75
Time-of-Use Opt-out 5.22 7.61 9.71 9.97 10.51
Variable Peak Pricing Rates 0.31 1.71 7.63 9.07 9.72
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 968 of 1105
Ancillary Services
Traditionally, ancillary services have been defined broadly as an option for Avista to use that stem from other DR programs at their disposal. This year, AEG wanted to provide Avista with feasible ancillary programs that are subsets of several programs defined above. AEG chose seven parent programs off of which to base ancillary options: Smart Thermostats Cooling, Smart Thermostats Heating, DLC Water Heating, CTA-2045 Water Heating, Electric Vehicle Charging, Third Party Contracts, and Battery Energy Storage. The results in this section are considered to be separate from the achievable potential discussed earlier in this chapter.
The ancillary programs were replicas of their parent programs with several exceptions. For participation, AEG assumed the same participation as the parent program for Battery Energy Storage, Electric Vehicle Charging, DLC Water Heating, and CTA-2045 Water Heating projecting that the same customers would also be eligible for an ancillary program. Participation in Third Party Contracts were based on the saturations of EMS systems for commercial customers in the PacifiCorp territory and the participation in Smart Thermostats Programs were assumed to be half of their respective parent programs.
For Impact assumptions, AEG assumed the same impacts for ancillary Battery Energy Storage, DLC Water Heating, and CTA-2045 Water Heating programs as their parent programs. For Ancillary Third Party Contracts, AEG assumed a 75% realization rate of the parent impact since there is more of a change a C&I customer will contribute less on an ancillary option. For ancillary Smart Thermostat and Electric Vehichle Charging options AEG assumed half the impacts of their respective parent programs.
Since the ancillary programs are subsets of the main programs, AEG assumed the ancillary programs would take half of the administrative and development costs of the parent programs to implement. In addition, to avoid double counting, equipment costs and O&M costs are assumed to be zero for the ancillary programs. The ancillary programs assume the same annual marketing and recruitment costs and incentive costs as the parent programs.
Winter Results
Table 6-40 and Figure 6-11 show the winter demand savings from individual DR options for selected years of the analysis. These savings represent stand-alone savings from all available DR options in Avista’s Washington and Idaho service territories.
Table 6-38 Achievable DR Potential by Ancillary Option (Winter MW @Generator)
2022 2023 2025 2035 2045
Ancillary Battery Storage 0.1 0.2 0.7 5.0 5.6
Ancillary Cooling - - - - -
Ancillary EV - - 0.2 2.8 15.1
Ancillary Heating 0.2 0.7 2.0 2.5 2.7
Ancillary Third Party 0.7 1.5 3.3 3.3 3.3
Ancillary DLC WH 0.5 1.6 4.9 5.5 5.5
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 969 of 1105
Figure 6-10 Achievable DR Potential by Ancillary Option (Winter MW @Generator)

For winter ancillary potential, the Ancillary CTA-2045 Water Heater Program is expected to have the highest potential by 2031 (13.91 MW), reaching 48.9 MW by 2045. This is due to the fact that full participation and impacts are assumed for this ancillary program. Ancillary EV has the second most potential and is expected to reach 1.43 MW by 2031 and 15.1 MW by 2045.
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Ancillary DLC WH
Ancillary CTA-2045 WH
Ancillary Third Party
Ancillary Heating
Ancillary EV
Ancillary Cooling
Ancillary Battery Storage
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 970 of 1105
Table 6-39 Winter Levelized Costs for Ancillary Options
Class DR Option WA ID
(2022-2031)
System Winter
Year 2031
Residential
Ancillary Battery Storage $91.29 $94.85
Ancillary Cooling
Ancillary EV $275.23 $275.76
Ancillary Heating $75.10 $75.98
Ancillary Third Party
Ancillary CTA-2045 WH $101.25
Ancillary DLC WH $87.27 $
C&I
Ancillary Battery Storage $89.74 $94.46
Ancillary Cooling
Ancillary EV
Ancillary Heating $198.09 $197.74
Ancillary Third Party $37.68 $37.54
Ancillary CTA-2045 WH $43.51
Ancillary DLC WH $42.99 $
The levelized costs are calculated using a ten year horizon between 2022 and 2031. Table 6-39 splits these out by residential and C&I sectors. On average, Ancillary Third Party Contracts are the cheapest option at a cost of $37.63 per kW while Ancillary Electric Vehicle Charging is the most expensive option at a cost of $275.41 per kW.
Table 6-40 Achievable DR Potential by Ancillary Option (Summer MW @Generator)
2022 2023 2025 2035 2045
Ancillary Battery Storage 0.1 0.2 0.7 5.0 5.6
Ancillary Cooling 0.4 1.3 4.3 9.3 15.2
Ancillary EV - - 0.2 2.8 15.1
Ancillary Heating - - - - -
Ancillary CTA-2045 WH 0.1 0.3 1.7 26.3 48.9
Ancillary DLC WH 0.5 1.6 4.9 5.5 5.5
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 971 of 1105

Similar to winter, the Ancillary CTA-2045 Water Heater Program is again expected to have the highest potential by 2045 (48.9 MW) during the summer season. Ancillary Smart Thermostats-Cooling is projected to have the second highest potential at 15.2 MW while Ancillary EV is projected to have the third most potential and is expected to reach 15.1 MW by 2045 (same as winter).
The levelized costs are calculated using a ten year horizon between 2022 and 2031. Table 6-41 splits these out by residential and C&I sectors. On average, Ancillary Third Party Contracts are the cheapest option at a cost of $38.49 per kW while Ancillary Electric Vehicle Charging is the most expensive option at a cost of $275.42 per kW.
Table 6-41 Summer Levelized Costs for Ancillary Options
Class DR Option WA ID (2022-2031)
System Winter
Year 2031
Residential
Ancillary Battery Storage $91.29 $94.85 $92.56 2.41
Ancillary Cooling $126.38 $127.03 $126.61 5.59
Ancillary EV $275.23 $275.76 $275.42 1.43
Ancillary Heating
Ancillary Third Party
Ancillary CTA-2045 WH $101.25 $101.25 13.91
Ancillary DLC WH $87.27 $87.27 4.73
C&I
Ancillary Battery Storage $89.74 $94.46 $91.63 0.41
Ancillary Cooling $59.69 $59.76 $59.72 1.58
Ancillary EV
Ancillary Heating
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Ancillary Third Party
Ancillary Heating
Ancillary EV
Ancillary Cooling
Ancillary Battery
Storage
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 972 of 1105
Ancillary Third Party $38.64 $38.19 $38.49 3.20
Ancillary CTA-2045 WH $43.51 $43.51 3.46
Ancillary DLC WH $42.99 $42.99 0.76

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 973 of 1105

MARKET PROFILES
This appendix presents the market profiles for each sector and segment for Washington and Idaho, in the embedded spreadsheet.

Avista 2020 Electric CPA Market Profile T
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 974 of 1105
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 975 of 1105

MARKET ADOPTION (RAMP) RATES
This appendix presents the Power Council’s 2021 Power Plan ramp rates we applied to technical potential to estimate Technical Achievable Potential.
Table B-1 Measure Ramp Rates Used in CPA
Ramp Rate 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041
LO12Med 11% 22% 33% 44% 55% 65% 72% 79% 84% 88% 91% 94% 96% 97% 99% 100% 100% 100% 100% 100%
LO5Med 4% 10% 16% 24% 32% 42% 53% 64% 75% 84% 91% 96% 99% 100% 100% 100% 100% 100% 100% 100%
LO1Slow 1% 1% 2% 3% 5% 9% 13% 19% 26% 34% 43% 53% 63% 72% 81% 87% 92% 96% 98% 100%
LO50Fast 45% 66% 80% 89% 95% 98% 99% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100%
LO20Fast 22% 38% 48% 57% 64% 70% 76% 80% 84% 88% 90% 92% 94% 95% 96% 97% 98% 98% 99% 100%
LOEven20 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%
LO3Slow 1% 1% 3% 6% 11% 18% 26% 36% 46% 57% 67% 76% 83% 88% 92% 95% 97% 98% 99% 100%
LO80Fast 76% 83% 88% 92% 95% 97% 98% 99% 99% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100%
Retro12Med 11% 11% 11% 11% 11% 10% 8% 6% 5% 4% 3% 3% 2% 2% 1% 1% 0% 0% 0% 0%
Retro5Med 4% 5% 6% 8% 9% 10% 11% 11% 11% 9% 7% 5% 3% 1% 1% 0% 0% 0% 0% 0%
Retro1Slow 0% 1% 1% 1% 2% 3% 4% 6% 7% 8% 9% 10% 10% 9% 8% 7% 5% 4% 2% 2%
Retro50Fast 45% 21% 14% 9% 6% 3% 1% 1% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%
Retro20Fast 22% 16% 11% 8% 7% 6% 5% 5% 4% 3% 3% 2% 2% 1% 1% 1% 1% 1% 1% 0%
RetroEven20 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5%
Retro3Slow 1% 1% 2% 3% 5% 7% 8% 10% 11% 11% 10% 9% 7% 6% 4% 3% 2% 1% 1% 1%

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 976 of 1105
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 977 of 1105

MEASURE DATA
Measure level assumptions and data are available in the “Avista 2019 DSM Potential Study Measure Assumptions” workbook provided to Avista alongside this file.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 978 of 1105
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 979 of 1105

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 980 of 1105

Applied Energy Group, Inc.
500 Ygnacio Valley Rd, Suite 250 Walnut Creek, CA 94596 P: 510.982.3525
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 981 of 1105

2021 Electric Integrated
Resource Plan

Appendix F – Avoided Cost
Calculations

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 982 of 1105
HLH 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
Jan 24.43 25.73 22.61 21.92 23.26 27.38 31.85 32.82 35.03 35.93 36.79 37.33 38.90 40.33 42.17 43.74 45.51 47.52 49.40 50.47 53.79 56.36 59.95 65.16 66.09
Feb 20.20 20.90 18.70 17.12 20.23 22.29 25.99 26.54 28.35 28.52 29.10 30.06 32.68 33.34 34.53 35.22 38.44 37.46 38.16 39.52 43.07 40.47 42.79 47.74 52.28
Mar 17.29 18.05 16.87 17.88 17.25 17.73 21.75 21.95 25.35 25.62 33.38 37.05 38.44 47.12 48.31 54.59 47.35 42.79 39.77 34.87 27.99 26.65 26.00 23.65 24.37
Apr 11.27 11.54 12.50 15.27 17.03 18.98 17.25 13.17 13.44 14.76 16.03 20.64 18.57 17.23 21.42 16.94 13.66 12.87 6.94 1.38 1.28 (4.59) (4.64) (4.49) (5.35)
May 4.19 4.27 5.38 3.73 1.90 1.88 (3.04) (5.79) (4.92) (6.97) (8.35) (6.48) (8.48) (8.98) (7.66) (8.96) (9.83) (9.12) (10.93) (11.68) (11.79) (8.60) (11.15) (6.29) (13.24)
Jun 12.90 13.08 13.26 15.20 11.82 11.44 10.37 4.05 3.50 (1.19) (5.18) (4.32) (4.59) (4.34) (4.61) (6.23) (7.00) (7.06) (7.14) (7.79) (8.86) (10.65) (11.41) (11.76) 4.07
Jul 17.63 18.71 19.54 20.21 21.31 22.63 27.02 25.00 26.30 27.62 24.41 27.22 24.31 20.34 16.87 15.73 15.22 16.06 13.36 12.00 3.21 1.74 3.27 2.51 7.21
Aug 23.01 24.46 24.94 25.02 28.64 28.72 33.69 31.21 32.73 34.26 34.16 34.97 34.84 35.77 36.12 41.79 39.30 39.63 37.60 40.65 33.33 32.47 33.60 34.88 45.16
Sep 21.49 22.18 24.48 22.95 25.95 27.71 31.76 29.25 30.17 30.38 30.56 32.42 33.92 33.38 33.39 35.20 35.83 38.12 43.03 43.18 39.70 37.69 42.43 42.73 48.04
Oct 19.43 20.01 21.18 20.37 23.53 23.91 27.88 24.91 27.07 28.52 27.00 29.20 31.42 32.22 33.31 34.78 37.47 38.73 48.08 44.96 55.39 62.05 56.09 46.98 47.34
Nov 18.66 19.83 18.54 19.75 21.37 25.40 27.33 27.27 30.10 29.68 31.47 31.25 34.24 37.06 41.58 39.99 44.82 48.13 49.28 51.38 59.59 53.91 55.49 57.91 75.39
Dec 24.42 25.90 24.50 26.20 27.78 35.07 36.07 35.69 38.04 38.24 40.61 41.41 44.23 47.14 50.76 50.06 52.85 58.36 64.13 69.24 69.52 70.34 71.29 80.69 96.11
LLH 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
Jan 20.71 22.12 19.32 19.54 20.37 24.06 30.78 31.48 34.35 35.39 34.92 36.37 37.02 39.20 42.45 43.55 44.74 46.55 47.59 49.67 52.97 53.45 57.44 61.27 62.63
Feb 17.13 18.01 15.91 15.42 18.11 21.01 26.28 26.39 28.74 28.15 29.42 29.70 34.09 33.72 34.94 35.81 41.06 42.65 42.86 44.59 49.98 48.97 52.49 59.16 63.65
Mar 12.67 12.91 12.55 13.82 14.80 16.71 22.94 22.88 27.96 32.58 43.05 51.43 49.90 62.49 66.45 74.05 73.54 71.61 70.17 66.35 57.80 54.95 47.83 40.07 39.18
Apr 9.85 10.07 11.64 15.53 20.54 22.57 25.15 23.33 26.87 29.06 28.74 36.57 29.27 28.86 36.05 32.80 27.00 33.24 21.58 12.60 9.07 (2.76) (5.65) (6.86) (8.01)
May (5.62) (3.69) (1.54) (8.96) (5.44) (5.74) (8.23) (11.58) (12.17) (15.65) (19.62) (13.55) (19.16) (21.27) (20.42) (22.38) (24.60) (17.58) (23.33) (23.33) (24.65) (24.78) (24.23) (17.14) (22.34)
Jun 6.82 7.69 7.54 3.33 8.07 4.94 0.85 (5.18) (7.39) (11.25) (16.13) (14.54) (14.67) (16.46) (18.29) (19.83) (18.59) (17.50) (16.39) (15.79) (18.19) (21.23) (19.89) (17.49) (9.89)
Jul 14.09 14.22 13.93 13.50 15.78 19.31 19.61 19.28 20.22 20.06 20.91 22.60 23.45 21.23 20.64 17.99 17.42 18.88 18.60 16.12 8.89 4.78 1.97 4.14 10.21
Aug 14.77 15.40 15.23 15.77 18.76 19.88 25.27 23.89 25.04 29.35 31.29 33.61 33.71 36.75 34.58 39.95 44.99 46.68 46.84 49.87 57.08 55.50 57.56 56.60 74.95
Sep 13.46 13.34 16.32 15.56 19.26 19.52 25.43 22.02 28.78 27.19 31.75 31.20 35.18 34.35 38.87 40.77 46.15 45.09 53.14 50.54 60.20 56.14 61.97 63.19 75.66
Oct 12.67 12.69 14.82 14.14 16.60 17.29 21.17 20.76 22.52 23.99 26.54 27.84 31.46 33.27 36.09 37.82 41.42 40.58 48.61 55.99 64.20 71.36 65.67 62.60 72.29
Nov 13.67 14.97 13.15 13.95 15.95 22.33 23.72 23.39 26.07 26.08 29.10 30.37 32.29 34.38 37.45 35.01 38.20 41.50 41.83 43.02 42.54 36.33 51.38 53.61 78.64
Dec 19.21 20.74 18.35 20.77 22.71 28.81 29.97 31.29 33.81 34.24 37.28 39.68 40.73 43.03 44.71 43.78 49.43 53.46 51.82 59.87 58.38 50.97 60.53 63.97 66.23
2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
- - - - - - 13.10 13.37 13.64 13.91 14.18 14.47 14.77 15.05 15.36 15.66 15.97 16.29 16.62 16.95 17.29 17.63 17.99 18.35 18.72
1. HLH (heavy load-hours) are defined as 6:00 am until 10:00 pm all days. LLH (light load-hours) are defined as all other hours.
2. Rate does not include adjustments for variable energy resource integration charges.
3. Capacity value is applied to all delivered energy during a calendar year.
Capacity Only Value Assuming Flat Delivery All Hours in a Year -- Example Rates For Large QF Resources, Not Applicable to Small QF
Hourly Values ($/MWh)
Estimated Avoided Costs
Energy Only Value Assuming Flat Delivery All Hours in a Year -- Example Rates For Large QF Resources, Not Applicable to Small QF
Hourly Values ($/MWh)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 983 of 1105
HLH 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
Jan 24.43 25.73 22.61 21.92 23.26 27.38 44.95 46.18 48.67 49.84 50.98 51.80 53.67 55.38 57.53 59.40 61.48 63.82 66.02 67.43 71.08 73.99 77.94 83.51 84.81
Feb 20.20 20.90 18.70 17.12 20.23 22.29 39.10 39.91 41.99 42.43 43.28 44.53 47.45 48.39 49.89 50.89 54.42 53.75 54.78 56.47 60.36 58.11 60.78 66.09 71.00
Mar 17.29 18.05 16.87 17.88 17.25 17.73 34.85 35.31 38.99 39.53 47.57 51.52 53.21 62.17 63.67 70.26 63.32 59.08 56.40 51.82 45.28 44.28 43.98 42.00 43.09
Apr 11.27 11.54 12.50 15.27 17.03 18.98 30.35 26.53 27.08 28.67 30.21 35.11 33.33 32.28 36.78 32.60 29.63 29.16 23.56 18.33 18.57 13.04 13.34 13.87 13.37
May 4.19 4.27 5.38 3.73 1.90 1.88 10.06 7.58 8.72 6.94 5.84 7.99 6.29 6.07 7.70 6.71 6.14 7.17 5.69 5.27 5.50 9.03 6.84 12.06 5.48
Jun 12.90 13.08 13.26 15.20 11.82 11.44 23.47 17.42 17.14 12.72 9.01 10.15 10.18 10.71 10.75 9.43 8.98 9.23 9.48 9.16 8.43 6.98 6.58 6.59 22.79
Jul 17.63 18.71 19.54 20.21 21.31 22.63 40.12 38.36 39.93 41.53 38.59 41.69 39.07 35.39 32.23 31.39 31.19 32.35 29.98 28.95 20.50 19.37 21.25 20.86 25.93
Aug 23.01 24.46 24.94 25.02 28.64 28.72 46.80 44.57 46.37 48.17 48.35 49.44 49.61 50.82 51.48 57.46 55.27 55.92 54.23 57.60 50.62 50.11 51.59 53.23 63.88
Sep 21.49 22.18 24.48 22.95 25.95 27.71 44.86 42.61 43.81 44.29 44.74 46.89 48.69 48.43 48.75 50.87 51.81 54.41 59.65 60.13 56.99 55.32 60.42 61.09 66.75
Oct 19.43 20.01 21.18 20.37 23.53 23.91 40.98 38.27 40.71 42.43 41.19 43.67 46.18 47.27 48.67 50.44 53.45 55.02 64.70 61.92 72.68 79.68 74.08 65.33 66.06
Nov 18.66 19.83 18.54 19.75 21.37 25.40 40.43 40.63 43.74 43.59 45.66 45.72 49.00 52.11 56.94 55.65 60.80 64.42 65.90 68.33 76.88 71.54 73.48 76.26 94.10
Dec 24.42 25.90 24.50 26.20 27.78 35.07 49.18 49.06 51.68 52.15 54.79 55.88 58.99 62.19 66.11 65.73 68.83 74.65 80.75 86.20 86.82 87.97 89.27 99.04 114.82
LLH 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
Jan 20.71 22.12 19.32 19.54 20.37 24.06 43.88 44.85 47.99 49.30 49.11 50.84 51.79 54.25 57.81 59.21 60.71 62.85 64.21 66.62 70.27 71.09 75.43 79.62 81.34
Feb 17.13 18.01 15.91 15.42 18.11 21.01 39.38 39.76 42.37 42.06 43.61 44.17 48.86 48.77 50.30 51.48 57.03 58.94 59.48 61.54 67.27 66.61 70.48 77.51 82.37
Mar 12.67 12.91 12.55 13.82 14.80 16.71 36.05 36.25 41.59 46.50 57.24 65.90 64.66 77.54 81.80 89.72 89.51 87.90 86.79 83.30 75.09 72.59 65.82 58.42 57.89
Apr 9.85 10.07 11.64 15.53 20.54 22.57 38.25 36.69 40.51 42.97 42.92 51.04 44.03 43.91 51.41 48.47 42.97 49.53 38.20 29.55 26.36 14.87 12.34 11.49 10.70
May (5.62) (3.69) (1.54) (8.96) (5.44) (5.74) 4.87 1.79 1.47 (1.74) (5.43) 0.92 (4.40) (6.22) (5.06) (6.72) (8.63) (1.28) (6.71) (6.38) (7.36) (7.14) (6.24) 1.21 (3.62)
Jun 6.82 7.69 7.54 3.33 8.07 4.94 13.95 8.18 6.25 2.67 (1.95) (0.07) 0.10 (1.41) (2.93) (4.17) (2.62) (1.21) 0.23 1.16 (0.89) (3.60) (1.90) 0.86 8.82
Jul 14.09 14.22 13.93 13.50 15.78 19.31 32.72 32.65 33.86 33.97 35.10 37.07 38.22 36.28 36.00 33.65 33.39 35.17 35.22 33.07 26.19 22.41 19.96 22.49 28.93
Aug 14.77 15.40 15.23 15.77 18.76 19.88 38.38 37.25 38.68 43.26 45.48 48.08 48.47 51.80 49.94 55.62 60.96 62.97 63.46 66.82 74.37 73.14 75.54 74.95 93.67
Sep 13.46 13.34 16.32 15.56 19.26 19.52 38.53 35.38 42.42 41.10 45.94 45.67 49.95 49.40 54.22 56.43 62.13 61.38 69.76 67.50 77.50 73.77 79.96 81.54 94.37
Oct 12.67 12.69 14.82 14.14 16.60 17.29 34.27 34.12 36.16 37.90 40.73 42.31 46.22 48.32 51.45 53.48 57.39 56.87 65.23 72.94 81.49 89.00 83.66 80.95 91.00
Nov 13.67 14.97 13.15 13.95 15.95 22.33 36.83 36.76 39.71 39.99 43.29 44.84 47.05 49.43 52.80 50.67 54.17 57.79 58.45 59.97 59.84 53.96 69.36 71.96 97.36
Dec 19.21 20.74 18.35 20.77 22.71 28.81 43.08 44.65 47.44 48.15 51.46 54.15 55.50 58.08 60.07 59.44 65.40 69.75 68.44 76.82 75.67 68.60 78.52 82.32 84.95
1. HLH (heavy load-hours) are defined as 6:00 am until 10:00 pm all days. LLH (light load-hours) are defined as all other hours.
2. After 15 years rates are escalated using growth rate between year 14 and year 15.
3. Rate does not include adjustments for variable energy resource integration charges.
Estimated Avoided Costs
Combined Energy and Capacity Value Assuming Flat Delivery All Hours in a Year -- Example Rates For Large QF Resources, Not Applicable to Small QF
Hourly Values ($/MWh)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 984 of 1105
First 3+ Year
Delivery On-System Montana Solar +Wood Geothermal History
Year Wind Wind Solar 4Hr Batt Hydro Biomass (off sys)Other $/kW-mo
2022 1.43 5.52 0.75 5.87 14.65 11.55 9.71 8.93 6.52
2023 1.60 6.21 0.84 6.61 16.47 12.99 10.92 10.04 7.33
2024 1.79 6.93 0.94 7.37 18.38 14.49 12.18 11.20 8.18
2025 2.10 8.13 1.10 8.64 21.56 17.00 14.29 13.14 9.59
First 3+ Year
Delivery On-System Montana Solar +Wood Geothermal History
Year Wind Wind Solar 4Hr Batt Hydro Biomass (off sys)Other $/kW-mo
2022 1.02 3.95 0.54 4.20 10.49 8.27 6.95 6.39 4.67
2023 1.25 4.85 0.66 5.16 12.87 10.15 8.53 7.84 5.73
2024 1.50 5.79 0.78 6.16 15.35 12.11 10.17 9.36 6.83
2025 1.92 7.43 1.01 7.90 19.70 15.54 13.05 12.01 8.77
First 3+ Year
Delivery On-System Montana Solar +Wood Geothermal History
Year Wind Wind Solar 4Hr Batt Hydro Biomass (off sys)Other $/kW-mo
2022 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00
2023 0.40 1.54 0.21 1.64 4.09 3.23 2.71 2.49 1.82
2024 0.81 3.15 0.43 3.35 8.36 6.60 5.54 5.10 3.72
2025 1.54 5.97 0.81 6.35 15.84 12.49 10.50 9.66 7.05
1. Capacity payments are based on an annual capacity value multiplied by the standardized
on-peak capacity contribution divided by a standardized capacity factor. Once QF output
exceeds that of the assumed capacity factor level, capacity payments will cease until the
next contract year.
2. Existing resources with 3 years of operating history will receive a $/MWh payment derived
using the $/kW-mo rate. To convert the $/kW-mo rate to a per-MWh rate, multiply the
$/kW-mo rate by 12 months and multiply it again by the capacity contribution factor
defined in tariff and then divide that figure by the average capacity factor over the same
number of years used to define the capacity contribution factor.
3. On-Peak Capacity Contribution Assumptions <3 Years Operating History:
On-System Wind: 5% Montana Wind: 30% Solar: 2% Solar + 4Hr Battery: 15%
Hydro: 61% Other: 100%
4. Standardized Capacity Factor Assumptions <3 Years Operating History:
On-System Wind: 31% Montana Wind: 49% Solar: 24% Solar + 4Hr Battery: 23%
Hydro: 37% Wood Biomass: 77% Geothermal (off-sys): 92%
5. Fixed rate is for contracts ending in 2035. Shorter terms will receive capacity payment
based on value provided over the term of the contract.
6. Capacity contribution payment with batteries is based on the size of the resource itself,
not the summation of the battery and resource. Battery size is assumed to be equal to a
multiple of the underlying resource capacity (e.g., 2 MW solar + 4 hr battery = 8 MWh
battery).
Hourly Capacity Value <3 Year History
RCW 80.80.40 Compliant Resources - Renewal Contracts Ending after 10 Years
Hourly Capacity Value <3 Year History
RCW 80.80.40 Non-Compliant Resources - Renewal Contracts Ending after 5 Years
Schedule 62 QF Avoided Costs
Specified-Term Standard Power & Short-Term Time of Delivery Capacity Rates
Hourly Values ($/MWh)
RCW 80.80.40 Compliant Resources - Contracts Ending after 15 Years
Hourly Capacity Value <3 Year History
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 985 of 1105
HLH 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
Jan 24.43 25.73 22.61 21.92 23.26 27.38 31.85 32.82 35.03 35.93 36.79 37.33 38.90 40.33 42.17 43.74 45.51 47.52 49.40 50.47 53.79 56.36 59.95 65.16 66.09
Feb 20.20 20.90 18.70 17.12 20.23 22.29 25.99 26.54 28.35 28.52 29.10 30.06 32.68 33.34 34.53 35.22 38.44 37.46 38.16 39.52 43.07 40.47 42.79 47.74 52.28
Mar 17.29 18.05 16.87 17.88 17.25 17.73 21.75 21.95 25.35 25.62 33.38 37.05 38.44 47.12 48.31 54.59 47.35 42.79 39.77 34.87 27.99 26.65 26.00 23.65 24.37
Apr 11.27 11.54 12.50 15.27 17.03 18.98 17.25 13.17 13.44 14.76 16.03 20.64 18.57 17.23 21.42 16.94 13.66 12.87 6.94 1.38 1.28 (4.59) (4.64) (4.49) (5.35)
May 4.19 4.27 5.38 3.73 1.90 1.88 (3.04) (5.79) (4.92) (6.97) (8.35) (6.48) (8.48) (8.98) (7.66) (8.96) (9.83) (9.12) (10.93) (11.68) (11.79) (8.60) (11.15) (6.29) (13.24)
Jun 12.90 13.08 13.26 15.20 11.82 11.44 10.37 4.05 3.50 (1.19) (5.18) (4.32) (4.59) (4.34) (4.61) (6.23) (7.00) (7.06) (7.14) (7.79) (8.86) (10.65) (11.41) (11.76) 4.07
Jul 17.63 18.71 19.54 20.21 21.31 22.63 27.02 25.00 26.30 27.62 24.41 27.22 24.31 20.34 16.87 15.73 15.22 16.06 13.36 12.00 3.21 1.74 3.27 2.51 7.21
Aug 23.01 24.46 24.94 25.02 28.64 28.72 33.69 31.21 32.73 34.26 34.16 34.97 34.84 35.77 36.12 41.79 39.30 39.63 37.60 40.65 33.33 32.47 33.60 34.88 45.16
Sep 21.49 22.18 24.48 22.95 25.95 27.71 31.76 29.25 30.17 30.38 30.56 32.42 33.92 33.38 33.39 35.20 35.83 38.12 43.03 43.18 39.70 37.69 42.43 42.73 48.04
Oct 19.43 20.01 21.18 20.37 23.53 23.91 27.88 24.91 27.07 28.52 27.00 29.20 31.42 32.22 33.31 34.78 37.47 38.73 48.08 44.96 55.39 62.05 56.09 46.98 47.34
Nov 18.66 19.83 18.54 19.75 21.37 25.40 27.33 27.27 30.10 29.68 31.47 31.25 34.24 37.06 41.58 39.99 44.82 48.13 49.28 51.38 59.59 53.91 55.49 57.91 75.39
Dec 24.42 25.90 24.50 26.20 27.78 35.07 36.07 35.69 38.04 38.24 40.61 41.41 44.23 47.14 50.76 50.06 52.85 58.36 64.13 69.24 69.52 70.34 71.29 80.69 96.11
LLH 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
Jan 20.71 22.12 19.32 19.54 20.37 24.06 30.78 31.48 34.35 35.39 34.92 36.37 37.02 39.20 42.45 43.55 44.74 46.55 47.59 49.67 52.97 53.45 57.44 61.27 62.63
Feb 17.13 18.01 15.91 15.42 18.11 21.01 26.28 26.39 28.74 28.15 29.42 29.70 34.09 33.72 34.94 35.81 41.06 42.65 42.86 44.59 49.98 48.97 52.49 59.16 63.65
Mar 12.67 12.91 12.55 13.82 14.80 16.71 22.94 22.88 27.96 32.58 43.05 51.43 49.90 62.49 66.45 74.05 73.54 71.61 70.17 66.35 57.80 54.95 47.83 40.07 39.18
Apr 9.85 10.07 11.64 15.53 20.54 22.57 25.15 23.33 26.87 29.06 28.74 36.57 29.27 28.86 36.05 32.80 27.00 33.24 21.58 12.60 9.07 (2.76) (5.65) (6.86) (8.01)
May (5.62) (3.69) (1.54) (8.96) (5.44) (5.74) (8.23) (11.58) (12.17) (15.65) (19.62) (13.55) (19.16) (21.27) (20.42) (22.38) (24.60) (17.58) (23.33) (23.33) (24.65) (24.78) (24.23) (17.14) (22.34)
Jun 6.82 7.69 7.54 3.33 8.07 4.94 0.85 (5.18) (7.39) (11.25) (16.13) (14.54) (14.67) (16.46) (18.29) (19.83) (18.59) (17.50) (16.39) (15.79) (18.19) (21.23) (19.89) (17.49) (9.89)
Jul 14.09 14.22 13.93 13.50 15.78 19.31 19.61 19.28 20.22 20.06 20.91 22.60 23.45 21.23 20.64 17.99 17.42 18.88 18.60 16.12 8.89 4.78 1.97 4.14 10.21
Aug 14.77 15.40 15.23 15.77 18.76 19.88 25.27 23.89 25.04 29.35 31.29 33.61 33.71 36.75 34.58 39.95 44.99 46.68 46.84 49.87 57.08 55.50 57.56 56.60 74.95
Sep 13.46 13.34 16.32 15.56 19.26 19.52 25.43 22.02 28.78 27.19 31.75 31.20 35.18 34.35 38.87 40.77 46.15 45.09 53.14 50.54 60.20 56.14 61.97 63.19 75.66
Oct 12.67 12.69 14.82 14.14 16.60 17.29 21.17 20.76 22.52 23.99 26.54 27.84 31.46 33.27 36.09 37.82 41.42 40.58 48.61 55.99 64.20 71.36 65.67 62.60 72.29
Nov 13.67 14.97 13.15 13.95 15.95 22.33 23.72 23.39 26.07 26.08 29.10 30.37 32.29 34.38 37.45 35.01 38.20 41.50 41.83 43.02 42.54 36.33 51.38 53.61 78.64
Dec 19.21 20.74 18.35 20.77 22.71 28.81 29.97 31.29 33.81 34.24 37.28 39.68 40.73 43.03 44.71 43.78 49.43 53.46 51.82 59.87 58.38 50.97 60.53 63.97 66.23
1. New resources must sign contracts through the end of 2035. Existing resources must execute 10-year contracts. Resources not
RCW 80.80.40 compliant must execute 5-year contracts. All new resource contracts must begin delivery within 3 years of execution;
renewal QF contract terms must begin at time of existing contract expiration.
2. HLH (heavy load-hours) are defined as 6:00 am until 10:00 pm all days. LLH (light load-hours) are defined as all other hours.
3. QF may cease deliveries during periods where prices are negative.
Schedule 62 QF Avoided Costs
Specified Term–Standard Power Energy Rates
Hourly Values ($/MWh)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 986 of 1105

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 987 of 1105

2021 Electric Integrated
Resource Plan

Appendix G – Transmission 10-
year plan (2020) and 2019-2020
Avista System Assessment

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 988 of 1105
2020 Avista System Plan
Prepared By: System Planning

SADDLE MOUNTAIN STATION UNDER CONSTRUCTION

Version Version Date Action Prepared By Reviewed By
A Nov 19, 2020 Draft posted for stakeholder review John Gross Damon Fisher
0 Dec 18, 2020 Finalized following stakeholder review John Gross David Thompson

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 989 of 1105
TABLE OF CONTENTS
I SYSTEM PLANNING OVERVIEW ................................................................................................................3
II SYSTEM PROJECT LIST .............................................................................................................................. 5
III MAJOR SYSTEM PROJECTS ...................................................................................................................... 15
1 COEUR D'ALENE SYSTEM REINFORCEMENT ................................................................................................................... 15
2 METRO STATION REBUILD ............................................................................................................................................ 17
3 SUNSET STATION REBUILD ........................................................................................................................................... 18
4 WEST PLAINS SYSTEM REINFORCEMENT ...................................................................................................................... 19
5 WESTSIDE STATION REBUILD ....................................................................................................................................... 20

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 990 of 1105
I SYSTEM PLANNING OVERVIEW
Avista’s System Planning department’s core responsibilities include the development of a
system plan for system reinforcements to meet transmission system needs for load growth,
adequate transfer capability, requests for generation interconnections, line and load
interconnections, and long-term firm transmission service.
The development of the system plan follows a two-year process with four phases.
Stakeholders have opportunities to participate in the development of the system plan by
collaborating with System Planning and providing comments.
• Phase 1 includes establishing the assumptions and models for use in the technical
studies, developing and finalizing a Study Plan, and specifying the public policy mandates planners will adopt as objectives in the current study cycle.
• Phase 2 includes performing necessary technical studies and development of the
Planning Assessment. The results of the technical studies are documented in the
Planning Assessment, including conceptual solutions to mitigate performance issues.
• Phase 3 includes providing the Avista System Plan report to stakeholders. The Avista System Plan will include documentation of the electrical infrastructure plan with preferred solution options. The resulting project list will include additional information regarding projects and system modifications developed through means other than the technical studies.1
• Phase 4 comprises the majority of year two in the two-year process and includes
refining the preferred plan of service. Conceptual projects identified in Phase 2 which
have not been fully developed in Phase 3 will be addressed in Phase 4.

1 Such other means may include, for example, generation interconnection or transmission service request study processes under the OATT, or
joint study team processes within the region.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 991 of 1105
Figure 1 provides a visual representation of the four phases throughout the two-year process.

FIGURE 1: AVISTA PLANNING ASSESSMENT TIMELINE

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 992 of 1105
II SYSTEM PROJECT LIST
Initiative # Project Name Driver Scope Targeted Date of Operation Status
Included in
Transmission Model
Big Bend System Reinforcement
- Bruce Siding Station Performance & Capacity
Scope not complete. New distribution station along Othello SS – Warden #2 115kV transmission line. Station may be an interconnection point for new transmission line used to integrate proposed renewable generation.
N/A Conceptual Not Scoped
32 Davenport Station Rebuild Asset Condition
Rebuild existing distribution station at nearby
greenfield site. Initial construction will include single 20MVA transformer with three feeders. Q3 2022 Budgeted
37 Little Falls Station Rebuild Asset Condition Scope not complete. Rebuild existing station in place. Q4 2023 Budgeted Not Scoped
117 Sprague Station Rebuild Asset Condition Scope not complete. Rebuild existing distribution station. N/A Conceptual Not Scoped
- Benton – Othello 115kV Transmission
Line Rebuild
Mandatory & Compliance
Reconductor Avista’s 26-mile section of the Benton – Othello Switching Station 115kV transmission line with 795 ACSS with a
minimum thermal capacity of 205MVA at 40°C.
Completed Q2 2020 Complete YES
- Chelan Stratford 115kV Transmission
Line Rebuild
Performance & Capacity
Scope not complete. Reconductor entire 35.1 miles of Chelan – Stratford 115kV transmission line and 1.2 miles of 115kV line from Headwork tap to Coulee City with 795 ACSS, with a minimum thermal capacity of 205MVA at 40°C.
N/A Conceptual Not Scoped
122 Devils Gap – Lind 115kV Transmission Line Rebuild Asset Condition Transmission line minor rebuild to address
age and condition of assets. Construction
Cabinet Gorge GSU Isolation 82 Cabinet Gorge GSU Protection Upgrade Performance & Capacity Install circuit breakers on high side of GSU. Q4 2024 Budgeted
Coeur d’Alene System
Reinforcement
- Canfield Station Performance & Capacity Scope not complete. New distribution station. N/A Conceptual Not Scoped
5 Dalton Station Rebuild Performance &
Capacity
Rebuild existing distribution station to two 30MVA transformers, six feeders, and looped-through transmission with circuit breakers. Q3 2020 Complete
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 993 of 1105
Initiative # Project Name Driver Scope Targeted Date of Operation Status Included in Transmission Model
- Pleasant View Station Performance &
Capacity
Scope not complete.
Rebuild existing station. N/A Conceptual
Not Scoped
105 Rathdrum Distribution Expansion Performance & Capacity Scope not complete. Increase existing distribution capacity. N/A Conceptual Not Scoped
80 Huetter Station Expansion Performance & Capacity
Scope not complete. Rebuild existing distribution station to two 30MVA transformers, six feeders, and looped-through transmission with circuit breakers.
Q4 2023 Budgeted Not Scoped
-
Coeur d’Alene – Pine Creek 115kV
Transmission Line Rebuild
Mandatory &
Compliance
Reconductor Coeur d'Alene - Pine Creek 115kV transmission line with 1272 ACSR
conductor and operate normally open switch as closed.
Completed Q4
2019 Complete YES
Open
46 Poleline (Prairie) Station Rebuild Performance & Capacity
Scope not complete. Construct new distribution station to replace Avista facilities at existing Prairie Station. New station to include two 30MVA transformers, six feeders, and looped-through transmission with circuit breakers.
Q4 2023 Budgeted Not Scoped
- Magic Corner Performance & Capacity
Convert the Ramsey – Rathdrum #3 and
Boulder – Post Falls 115kV transmission lines into Boulder – Rathdrum and Post Falls –
Ramsey 115kV transmission lines by
swapping jumpers on the “magic corner” pole where the transmission lines intersect. Changing the transmission lines will allow the
Coeur d’Alene – Pine Creek 115kV transmission line to be operated normally closed.
Q2 2021 NO
East Coeur d’Alene Lake System Reinforcement
12 Carlin Bay Station Performance & Capacity
Construct new distribution station to include single 20MVA transformer and three feeders. Transmission integration to include constructing a new radial transmission line
from O’Gara Station to Carlin Bay and
rebuilding the existing O’Gara Station to a
switching station. New microwave communication paths will be established to
O’Gara Station.
Q1 2025 Budgeted
89 Saint Maries Station Expansion Performance & Capacity
Construct a fourth distribution feeder at the existing Saint Maries Station. SCADA and communication infrastructure will be added. Q1 2022 Budgeted
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 994 of 1105
Initiative # Project Name Driver Scope Targeted Date of Operation Status Included in Transmission Model
128
Benewah – Pine
Creek 230kV Transmission Line
Rebuild
Asset Condition Scope not complete. Design 2025 Rebuild transmission line. N/A Conceptual Not Scoped
Idaho/Lewis County System Reinforcement
34 Grangeville Station Rebuild Asset Condition
Rebuild existing station to include a main bus with transmission lines terminated at circuit breakers. New distribution facilities to include a 13.2kV and a 34.5kV transformer.
N/A Conceptual
36 Kooskia Station
Rebuild Asset Condition
Scope not complete. Rebuild existing distribution station. Initial
construction will include single 20MVA transformer with two feeders.
Q4 2025 Budgeted
Not Scoped
Kettle Falls Stability 96 Kettle Falls Protection System Upgrade Mandatory & Compliance
Upgrade existing protection schemes on the Addy – Kettle Falls and Colville – Kettle Falls
115kV transmission lines. New relays at Kettle Falls Station and a new communication path from Kettle Falls to Mount Monumental are required.
2022 Budgeted NO
Lewiston/Clarkston System Reinforcement
64 Hatwai – Lolo #2 230kV Transmission
Line
Mandatory & Compliance
Scope not complete. Construct new 230kV transmission line from Hatwai to Lolo, new transmission line terminal
at Lolo Station and request interconnection at
BPA’s Hatwai Station.
2025 Budgeted Not Scoped
6 LOID Station Customer Requested
Scope not complete. New distribution station in the Lewiston Orchards area. Q4 2025 Budgeted Not Scoped
108 Wheatland Station Performance & Capacity Scope not complete. New distribution station in the Lewiston area. N/A Conceptual Not Scoped
109 Tenth & Stewart Station Expansion Performance & Capacity
Scope not complete. Rebuild and expand existing distribution station. N/A Conceptual Not Scoped
42 Bryden Canyon Station Asset Condition
Scope not complete.
New distribution station to replace existing distribution facilities at South Lewiston Station.
Q1 2023 Budgeted Not Scoped
42 South Lewiston
Station Rebuild Asset Condition
Scope not complete. Rebuild existing station including relocating distribution facilities to Bryden Canyon Station and constructing a switching station with circuit breaker terminated transmission lines.
Q1 2023 Budgeted
Not Scoped NO
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 995 of 1105
Initiative # Project Name Driver Scope Targeted Date of Operation Status Included in Transmission Model
79 Dry Gulch Station Upgrade Customer Requested
Upgrade of facilities for the replacement of
PacifiCorp’s 69kV transformer with the 69kV transmission line to be operated normally
open.
2020 Complete NO
62 Lolo Transformer Replacement Mandatory & Compliance
Replace Lolo #1 230/115kV transformer with 250MVA rated transformer. Replace Lolo #2 230/115kV transformer with 250MVA rated transformer. 115kV circuit breakers, bus work and other capacity-limiting elements will be replaced. Circuit switchers at Lolo and Sweetwater stations will be replaced.
Q3 2023
Q3 2024
Budgeted NO
41 Pound Lane Station Rebuild Asset Condition Scope not complete. Rebuild existing distribution station. N/A Conceptual Not Scoped
124 Lolo – Oxbow 230kV Transmission Line Rebuild Asset Condition Rebuild transmission line.
Q2 2021 for first phase 2025 for completion
Budgeted
Metro Station Rebuild
125 Downtown Transmission Cable Replacement Asset Condition
Replace existing Metro – Post Street and Post Street – Third & Hatch 115kV transmission line cables with 1500 kcmil
XLPE.
Q1 2021 Construction NO
38 Metro Station Rebuild Asset Condition
Rebuild existing substation at new location. 115kV bus to be a 6-position ring: 2 – 30MVA xfmrs, 2 – 115kV UG lines from PST, 2 – 115kV OH lines; switchgear on the 13kV side, both Network and Distribution feeders
Q1 2024 Budgeted YES
North Spokane System Reinforcement
81 Beacon – Francis & Cedar – Waikiki
Reconfiguration
Performance & Capacity
Scope not complete. Request new interconnection to Bell Station and loop existing Beacon – Francis & Cedar 115kV transmission line into Bell Station. Waikiki Station can then be served normally by the Bell – Francis & Cedar line.
N/A Conceptual Not Scoped
129 Mead – Colbert – Milan 115kV Transmission Line
Performance & Capacity
Scope not complete.
Construct a new 115kV transmission line starting from north Spokane to pick up Mead, Colbert, and Milan stations.
N/A Budgeted Not Scoped
50 Florida & Dalke Station Performance & Capacity Scope not complete. New distribution station on the Beacon – Bell Q4 2025 Budgeted Not Scoped
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 996 of 1105
Initiative # Project Name Driver Scope Targeted Date of Operation Status Included in Transmission Model
#1 115kV transmission line in the Hillyard
area.
15 Hawthorne Station Performance & Capacity
Scope not complete. New switching station with distribution facilities located in north Spokane near Bell Station. 115kV interconnection will be along the Beacon – Francis & Cedar corridor and can be a starting point for new transmission line toward Mead Station.
Q4 2025 Budgeted Not Scoped
98 Midway Station Performance & Capacity
Scope not complete.
New distribution station located north of Spokane along the Bell – Addy 115kV
transmission line.
Q1 2023 Budgeted Not Scoped
106 Waikiki Station Expansion Performance & Capacity
Scope not complete.
Increase existing distribution capacity at Waikiki Station. N/A Conceptual Not Scoped
111 Lyons & Standard
Station Expansion
Performance &
Capacity
Scope not complete. Increase existing distribution capacity at Lyons & Standard Station. N/A Conceptual
Not Scoped
40 Northwest Station Rebuild Asset Condition Scope not complete. Rebuild existing Northwest Station. Q4 2024 Budgeted Not Scoped
Palouse System Reinforcement
2 Center Street Station Performance & Capacity
Scope not complete. New distribution station located in the Pullman area. 2025 Budgeted
Not Scoped
47 Stateline Station Performance & Capacity
Scope not complete. New distribution station located between Pullman and Moscow. Q1 2024 Budgeted Not Scoped
Tamarack Station Performance & Capacity
Scope not complete.
New distribution station located in the Moscow area. N/A Conceptual Not Scoped
112 Moscow City Station Rebuild Asset Condition Scope not complete. Rebuild existing Moscow City Station. N/A Conceptual Not Scoped
North Moscow Station
Expansion
Performance &
Capacity
Scope not complete. Increase distribution capacity at the existing North Moscow Station. N/A Conceptual
Not Scoped
77 Palouse Area Transformation Mandatory & Compliance
Scope not complete. Install new 230/115kV transformer at Shawnee Substation with low- and high-side breakers
N/A Conceptual Not Scoped
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 997 of 1105
Initiative # Project Name Driver Scope Targeted Date of Operation Status Included in Transmission Model
Install breaker at high-side of Shawnee
230/115kV No. 1 XFMR
114 Potlach Station Rebuild Asset Condition Scope not complete. Rebuild existing Potlatch Station. N/A Conceptual Not Scoped
Rattlesnake Flat I
Wind Integration
99 Neilson Station Customer Requested
Build new 115kV Switching Station for Saddle Mtn POI. Initial configuration 3-terminal ring; final 6-terminal breaker and a half. Q3 2020 Complete YES
99 Lind – Warden 115kV Transmission Line Rebuild
Customer Requested
Upgrade existing Lind – Warden 115kV
transmission line to 314MVA capacity including upgrades to terminal equipment at
each station. New conductor is 795 ACSS.
Q4 2019 Complete YES
99 Lind – Washtucna 115kV Transmission Line Rebuild
Customer Requested
Upgrade existing Lind – Washtucna 115kV transmission line between Lind and the new Nielson Station to 314MVA capacity including upgrades to terminal equipment at Lind Station. New conductor is 795 ACSS.
Q4 2019 Complete YES
Saddle Mountain
75 Saddle Mountain
Station
Mandatory &
Compliance
Construct a 3-position 230kV DBDB arrangement with space for two future positions at the line crossing of the Walla
Walla – Wanapum 230kV and Benton – Othello 115kV Lines
Construct a 4-position 115kV breaker and a half arrangement with space for four future positions Install 1-230/115kV transformer rated at 250MVA.
Q4 2020 Construction YES
75
Othello SS – Warden #1 115kV Transmission Line Upgrade
Mandatory & Compliance
Reconstruct Othello SS – Warden #1 115kV transmission line to minimum 205MVA including upgrades to terminal equipment at both stations.
Q1 2019 Complete YES
75
Othello SS – Warden #2 115kV
Transmission Line Upgrade
Mandatory &
Compliance
Reconstruct Othello SS – Warden #2 115kV transmission line to minimum 205MVA
including upgrades to terminal equipment at all stations.
Q4 2021 Construction YES
75 Othello – Saddle Mountain 115kV Transmission Line
Mandatory & Compliance
Construct 11 miles of 115kV line with a minimum summer rating of 205MVA from Saddle Mountain Station to the new Othello City station with a N/O tap to existing S. Othello Station.
Q4 2021 Construction NO
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 998 of 1105
Initiative # Project Name Driver Scope Targeted Date of Operation Status Included in Transmission Model
75 Othello Station Rebuild Mandatory & Compliance
Reconstruct Othello Station to a 3-position
breaker and a half with 2 – 30MVA transformers at new property. Q3 2022 Construction NO
Sandpoint System Reinforcement
56 Bronx Station Rebuild Performance &
Capacity
Scope not complete. Reconstruct existing Bronx Station to include distribution facilities. 2025 Budgeted
Not Scoped
74 Sandpoint Transmission Addition Mandatory & Compliance
Scope not complete. Build a new 37-mile line from Rathdrum to Sandpoint with a conductor capable of providing a minimum of 205MVA capacity.
Add three circuit breakers at Sandpoint Substation. Add a position and circuit breaker
at Rathdrum Substation.
N/A Conceptual Not Scoped
-
Cabinet – Bronx –
Sand Creek 115kV Transmission Line Upgrade
Mandatory & Compliance
Upgrade the Bronx – Cabinet and Bronx –
Sand Creek 115kV transmission lines to 205MVA capacity including terminal equipment at all stations.
2017 Complete YES
70 Cabinet – Noxon 230kV Transmission Line Rebuild
Performance & Capacity Reconductor entire 18.51 miles of line to 1590 ACSS. N/A Conceptual Not Scoped
Silver Valley System Reinforcement
90 Mission Station Expansion Performance & Capacity
Scope not complete.
Increase distribution capacity at the existing North Moscow Station. N/A Conceptual Not Scoped
29 Big Creek Station Rebuild Asset Condition Scope not complete. Rebuild existing Big Creek Station. 2025 Budgeted Not Scoped
126 Noxon – Pine Creek 230kV Transmission Line Rebuild Asset Condition
Scope not complete. Reconductor 42.87 miles of 43.51 miles of line to 1590 ACSS. Existing line is partially constructed as double circuit transmission line.
2025 Budgeted Not Scoped
South Spokane System Reinforcement 67 Ninth & Central 230kV Expansion Mandatory & Compliance
Scope not complete. Build new Ninth and Central 230kV Double
Bus Double Breaker substation to include 1-230/115kV (250MVA) transformer associated with two Circuit Breakers. Loop Beacon – Bell No.4 or No.5 230kV Line to reconfigure to Bell – Ninth and Central 230kV Line Build new 230kV line section from Beacon to Ninth and Central alongside existing 115kV
N/A Conceptual Not Scoped
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 999 of 1105
Initiative # Project Name Driver Scope Targeted Date of Operation Status Included in Transmission Model
line (Either Beacon – Ninth and Central No. 1
or No. 2 115kV Line is adequate.
54 Downtown West Station Performance & Capacity
Scope not complete. New distribution station located on the Metro
– Sunset 115kV transmission line. 2025 Budgeted Not Scoped
55 East Central New Substation Performance & Capacity
Scope not complete. New distribution station located on the Ninth & Central – Third & Hatch 115kV transmission line.
2024 Budgeted Not Scoped
44 Southeast Station Expansion Performance & Capacity
Replace 20MVA XFMR#2 with 30MVA and
add sixth feeder (Complete). Upgrade 115kV loop-through with capacity for 314MVA.
Transmission Q4 2021 Construction YES
110 College & Walnut Station Rebuild Asset Condition Scope not complete. Rebuild existing College & Walnut Station. N/A Conceptual Not Scoped
60
Ninth & Central – Sunset 115kV Transmission Line Upgrade
Performance & Capacity
Replace the 795 AAC and ACSR conductor on the Ninth & Central – Sunset 115kV transmission line with 795 ACSS with E3X coating to match the rest of the line.
Q3 2023 Budgeted NO
93
Beacon – Ross Park
115kV Transmission Line Rebuild
Mandatory & Compliance Rebuild existing Beacon – Ross Park 115kV transmission line. No capacity increase. 2021 Budgeted
Spokane Valley Transmission Reinforcement
59 Irvin Station Mandatory & Compliance
Construct the Irvin Station terminating the Beacon – Boulder #1 and #2, Irvin – IEP, and Irvin – Opportunity 115kV transmission lines as a breaker and a half configuration
Q1 2022
Partialy Complete Construction YES
49 Irvin Distribution Performance & Capacity Scope not complete. Add distribution facilities to Irvin Station. N/A Conceptual Not Scoped
30 Chester Station
Rebuild Asset Condition Scope not complete.
Rebuild existing Chester Station. N/A Conceptual
Not Scoped
57 Barker Station Expansion Performance & Capacity Scope not complete. Increase capacity at existing Barker Station. N/A Conceptual Not Scoped
123 Beacon – Boulder #1 115kV Transmission Line Rebuild Asset Condition Rebuild the existing Beacon – Boulder #1 115kV transmission line from Irvin to SIP. 2022 Budgeted NO
59
Beacon – Boulder #2
115kV Transmission Line Rebuild
Mandatory & Compliance
Rebuild the existing Beacon – Boulder #2
115kV transmission line from Beacon to Millwood to 795 ACSS conductor. N/A Deferred NO
43 Valley Station Rebuild Asset Condition Scope not complete. Rebuild existing Valley Station. Q4 2024 Budgeted Not Scoped
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1000 of 1105
Initiative # Project Name Driver Scope Targeted Date of Operation Status Included in Transmission Model
Stevens/Ferry County System Reinforcement
-
Addy – Devils Gap
115kV Transmission Line Upgrade Asset Condition
Reconductor 5.19 miles (rebuild between
Ford and Long Lake Tap) of limiting conductor which consist of 266.8 ACSR and
397.5 ACSR conductor resulting in a capacity limitation of 71.5MVA at 40°C, to be rebuilt to a capacity of 150MVA at 40°C (likely 240MVA)
Q1 2019 Complete YES
91 Long Lake Station Rebuild Asset Condition
Scope not complete. Relocation of existing GSU transformer from within Long Lake HED to an outside station. Existing 115kV station is located in the powerhouse and will be relocated to an
adjacent outdoor site.
N/A Conceptual Not Scoped
101 Long Lake Station Expansion Performance & Capacity
Scope not complete.
Increase capacity of the distribution facilities at the Long Lake distribution station. N/A Conceptual Not Scoped
8 Addy – Gifford 115kV Transmission Line Rebuild Asset Condition Scope not complete. Reconstruct portions of the radial Addy – Gifford 115kV transmission line. 2026 Budgeted
Not Scoped
Sunset Station Rebuild 26 Sunset Station Rebuild Mandatory & Compliance Rebuild the existing Sunset Station as breaker and a half configuration. Q2 2022 Construction
West Plains System Reinforcement
53 Flint Road Station Performance & Capacity
Scope not complete. New distribution station located north of Spokane along the Airway Heights - Sunset 115kV transmission line.
Q3 2022 Budgeted Not Scoped
104 Four Lakes Capacitor Performance &
Capacity
Scope not complete. Install capacitors at the existing Four Lakes Station. N/A Conceptual
Not Scoped
100 Melville Station Performance & Capacity
Scope not complete. New switching station near existing tap to Four Lakes Station off the South Fairchild Tap 115kV transmission line. Construct new
transmission line from Airway Heights to Melville including passing through Russel
Road and Craig Road distribution stations. Requires new transmission line terminal at existing Airway Heights Station.
Q1 2025 Budgeted Not Scoped
- Russel Road Performance & Capacity Scope not complete. New distribution station located south of N/A Conceptual Not Scoped
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1001 of 1105
Initiative # Project Name Driver Scope Targeted Date of Operation Status Included in Transmission Model
Airway Heights along the new Airway Heights
- Melville 115kV transmission line.
131 Garden Springs 115kV Station Performance & Capacity
Construct new 115kV portion of Garden Springs Station at the existing Garden Springs switching location. New station will terminate Airway Heights – Sunset and Sunset – Westside 115kV transmission lines including the South Fairchild Tap.
Q4 2024 Budgeted
131 Garden Springs 230kV Station Performance & Capacity
Construct new 230kV portion of Garden Springs Station including two 250MVA
nominal 230/115kV transformers. Construct new 230kV transmission line from Garden
Springs to a new switching station at interconnection point on the BPA Bell –
Coulee #5 230kV transmission line.
N/A Budgeted
Westside Station Rebuild 58 Westside Station Rebuild Mandatory & Compliance
Replace the existing Westside #2 230/115kV transformer and construct necessary bus work and breaker positions. Reconstruct 230 and 115kV buses to double bus double breaker 3000/2000 Amp standard. Phase 4: Complete bus work to double bus, double breaker on both the 230kV and 115kV buses
XFMR and 230
2x2 Q1 2021 Q3 2024 for
complete rebuild
Construction YES
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1002 of 1105
III MAJOR SYSTEM PROJECTS
The following list is a subset of the project list provided in Section II. The subset of projects was selected based on their relative impact to the system performance and the project scope has been substantially determined. A general problem statement and summary of project
scope is provided. Detailed project reports may be available and could have more recent
information.
1 COEUR D'ALENE SYSTEM REINFORCEMENT
The Coeur d’Alene and Post Falls areas in northern Idaho have seen high load growth rates
which are expected to continue. Area distribution stations are becoming heavy loaded with
equipment operating above 80% of their applicable facility ratings in peak summer scenarios. The local transmission system is served by two 230/115kV autotransformers and a single 115kV transmission line. An additional transmission line can connect to the area but has been historically operated normally open. The autotransformers along with the 115kV transmission lines feeding Coeur d’Alene load may overload for multiple contingency events during
moderate to heavy loading during all seasons.
The Coeur d’Alene System Reinforcement initiative includes several projects intended to
increase distribution system capacity. Rebuilds and expansion of existing stations at Pleasant
View, Rathdrum, Huetter and Prairie will provide increased transformation capacity and
additional feeders to serve the area. The Magic Corner project, which changes the Boulder –
Post Falls and Ramsey – Rathdrum 115kV transmission lines into the Boulder – Rathdrum and
Post Falls – Rathdrum 115kV transmission lines, will allow the Coeur d’Alene – Pine Creek
115kV transmission line to be operated normally closed. Operating the transmission line normally closed provides an additional transmission source into the area.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1003 of 1105
1
1
2
Modify Magic Corner pole located at Poleline and Chase to
convert the Boulder – Post Falls and Ramsey – Rathdrum #3 115
kV transmission lines into the Boulder – Rathdrum and Post Falls
– Ramsey 115 kV transmission line.
Operate switch A429 at Blue Creek on the Coeur d Alene – Pine
Creek 115 kV Transmission Line normally closed. Not shown on
drawing.

FIGURE 2: MAGIC CORNER PROJECT DIAGRAM

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1004 of 1105
2 METRO STATION REBUILD
Metro Station, located in downtown Spokane, is one of two stations serving the downtown
distribution network. Much of the major equipment in this station is now unsupported by the manufacturer. Legacy oil tanks beneath the site pose an environmental problem and limit modifications to upgrade the existing station. Underground transmission cables to this site in need replacement. Transformer and switchgear spares are unavailable or difficult to install in an outage scenario. Various other condition issues, such as the 115kV breakers, insulators,
and panel house, also exist at this site.
The Metro Station Rebuild project is a full rebuild of the station on a green field site. In addition to the existing Metro – Sunset and Metro – Post Street lines, the Post Street – Third & Hatch line will now be terminated in the Metro station to provide additional transmission configurations to support the network load served out of Metro station and to provide additional redundancy and resiliency options throughout the Spokane urban area.

Future
12F2
1363213637
Future
12F1
13636 1363313634Future
Network
Future
Network
13638
Post Street
Tie
Post Street #1
Post Street #2
Sunset
Third & Hatch
2
Construct new 115 kV station to replace
existing Metro Station.
New 30MVA nominal 115/13.8 kV
transformers.
1
1
2

FIGURE 3: METRO STATION REBUILD PROJECT DIAGRAM
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1005 of 1105
3 SUNSET STATION REBUILD
The existing circuit breakers at the Sunset Station do not have sufficient short circuit
interrupting capability for close-in faults on the connected transmission lines. The available fault current increases with the necessary transmission system expansion to address other system deficiencies (i.e. Westside transformer replacement).
The Sunset Station Rebuild project is a complete station rebuild on adjacent property to the existing station. The 115kV station configuration will be a breaker and a half. The distribution portion of the station will include two 30 MVA transformers, six feeders, and auxiliary feeder positions on each bus.

2
1 Six terminal 115kV breaker and a half
breaker arrangement (one future
terminals.)
Two distribution transformers per
Distribution Planning requirements.
Shawnee Ninth & Central
115 kV
1
Garden Springs #2
Garden Springs #1
Downtown West
2

FIGURE 4: SUNSET STATION REBUILD PROJECT DIAGRAM

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1006 of 1105
4 WEST PLAINS SYSTEM REINFORCEMENT
The West Plains and Sunset area (up to 245MW) is served by four 115kV transmission lines,
which may overload for multiple contingency events during summer loading. Existing mitigation projects (Garden Springs – Sunset 115kV Transmission Line rebuild and the Ninth & Central – Sunset 115kV Transmission Line rebuild) help reduce the amount of overloading, but do not correct known contingency issues.
The West Plains System Reinforcement initiative includes the construction of a new 230kV
transmission source into the area. A new transmission line is proposed to connect the Bell –
Coulee corridor to a new Garden Springs Station. The Garden Springs Station will include two 250MVA nominal 230/115kV transformers and intersect the Sunset – Westside and Airway Heights – Sunset 115kV transmission lines. Additional reinforcements in the area to support distribution system expansion and interconnect new distribution stations includes a new 115kV transmission line from Airway Heights Station to a new Melville Station which intersects the
South Fairchild 115kV transmission line Tap near Hallett & White Station. New distribution
stations at Flint Road and Russel Road will increase transformation capacity and provide
additional feeders to serve the increased distribution system demands.

FIGURE 5: GARDEN SPRINGS STATION PROJECT DIAGRAM

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1007 of 1105
5 WESTSIDE STATION REBUILD
Outages causing loss of 230/115kV transformers at the BPA Bell or Avista Beacon Station, or
outages causing increased impedance from the Bell and/or Beacon Stations to the area’s distribution stations cause the Westside #1 and #2 230/115kV transformers to exceed their applicable facility ratings. The Westside Station Rebuild project is a complete station rebuild which includes the replacement of the existing Westside #1 and #2 230/115kV transformers with 250MVA nominal capacity transformers. Both the 230kV and 115kV configuration will be
double bus, double breaker.

2
1 Six terminal 230kV double bus, double
breaker arrangement. Transmission line and transformer terminal position will not
impact System performance.
Two 230/115kV, 250MVA,
Autotransformer w/ LTC +/- 5%
Eight terminal 115kV double bus, double breaker arrangement. Transmission line
and transformer terminal position will not impact System performance.
Two step capacitor bank. Capacity TBD.
Two distribution transformers per Distribution Planning requirements.
3
4
5
230 kV
Bell
Sunset
College & Walnut Northwest
Nine Mile
115 kV
Grand Coulee
TBDNorth/East Direction
Garden Springs
TBDSouth/West Direction
TBDNorth/East Direction
1
2
34
5

FIGURE 6: WESTSIDE STATION REBUILD PROJECT DIAGRAM

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1008 of 1105
2019-2020 Avista System Assessment
Electrical System Planning Assessment

NEILSON SWITCHING STATION – RATTLESNAKE FLAT WIND INTEGRATION

Version History
Version Date Action Prepared By Reviewed By
0 11/15/19 Draft posted for stakeholder review Spratt Gross
1 12/20/19 Final Team Gross
1.1 1/9/20 De minimis Spacek Gross 2 12/18/20 2020 Update, confirmed 2019 results Gross Spacek
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1009 of 1105
TABLE OF CONTENTS
I EXECUTIVE SUMMARY ............................................................................................................................. 4
II INTRODUCTION ....................................................................................................................................... 6
III TECHNICAL STUDY OVERVIEW ............................................................................................................... 8
1 ASSUMPTIONS ................................................................................................................................................................ 8
2 TECHNICAL STUDIES .................................................................................................................................................... 10
3 POINT OF CONTACT ..................................................................................................................................................... 10
IV PROJECT AND ISSUE LIST ......................................................................................................................... 11
1 SUMMARY ...................................................................................................................................................................... 11
2 IDENTIFIED SYSTEM PROJECTS ....................................................................................................................................... 15
3 COMPLETED PROJECTS .................................................................................................................................................. 31
V TECHNICAL ANALYSIS RESULTS ............................................................................................................. 32
1 STEADY STATE CONTINGENCY ANALYSIS ...................................................................................................................... 32
2 VOLTAGE STABILITY ANALYSIS .....................................................................................................................................48
3 STABILITY CONTINGENCY ANALYSIS ............................................................................................................................ 49
5 SPARE EQUIPMENT ANALYSIS ....................................................................................................................................... 52
6 SHORT CIRCUIT ANALYSIS ............................................................................................................................................ 54
8 FEEDER CAPACITY ANALYSIS ........................................................................................................................................ 55
AVISTA GENERAL INFORMATION .......................................................................................... 56
TRANSMISSION MODELS ........................................................................................................ 58
STEADY STATE CONTINGENCY ANALYSIS RESULTS ............................................................ 60
SPARE EQUIPMENT ANALYSIS RESULTS .............................................................................. 134
SHORT CIRCUIT ANALYSIS RESULTS .................................................................................... 157
STABILITY CONTINGENCY ANALYSIS RESULTS ................................................................... 163
VOLTAGE STABILITY ANALYSIS RESULTS ............................................................................ 189
FEEDER CAPACITY ANALYSIS RESULTS ................................................................................ 191
STUDY PLAN .......................................................................................................................... 199
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1010 of 1105
2020 Update
Version 2 of the 2019-2020 Planning Assessment is unchanged from Version 1 published in 2019. A companion document has been created, 2020 Avista System Plan, which provides an updated project list with targeted date of operation for each project. The updated project list is
also used as an update to the Attachment K Local Planning Report and proposed Single
System Projects developed during year one of the biennial process.
Steady state, short circuit, and stability studies performed during 2019 (less than five calendar
years old) have been determined to be still relevant as no material changes have occurred to
the System represented by the studies.
A comparison of the modeled scenarios used in the 2019 studies to recent WECC approved
base cases was performed using PowerWorld Simulator’s Difference Case tool. No material
changes to the model, neither new, removed, nor modified equipment, were discovered.
Projects constructed during 2020 had been modeled and studied in the 2019 studies. The
2020 summer peak (2141 MW) did not exceed the peak summer load of 2319 MW studied in
the 2019 studies. The 2019/2020 winter peak (2113 MW) did not exceed the peak winter load of 2444 MW studied in the 2019 studies.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1011 of 1105
I EXECUTIVE SUMMARY
Avista completed a comprehensive study to examine the electrical system’s reliability under
normal operating conditions along with prescribed planning events that include single and
multiple outage conditions, commonly referred to as N-1-1. The results of this current study
are compared to the benchmark of earlier studies to characterize the system’s operational
changes over time. Mitigation plans are provided in response to identified functional or
operational issues.
Avista’s System Planning process is designed to be transparent, open, and understandable,
treating all customer classes on an equal and comparable basis. The study plan methodology
develops operable solutions for conditions or states that negatively impact system reliability,
adequacy, or security. The proposed solutions may include wired and non-wired options that either prevent or resolve the reliability concerns.
The impact of operational contingencies, generally defined as the unexpected failure or outage of an electrical system component, are evaluated by Avista through analysis of seasonal load and generation variations through a multi-year study. Of the contingencies evaluated, none resulted in Instability Cascading or Uncontrolled Separation conditions, confirming there are no Interconnection Reliability Operating Limits that would adversely impact the reliable operation
of the Bulk Electric System.
Key findings from these studies include:
• No thermal criteria issues were identified under normal operational conditions
regardless of season.
• Minor voltage exceedance issues were identified on the 115kV transmission system
when evaluated under light load conditions.
• Heavy summer load conditions continue to drive the most significant system stressors,
especially for transmission line and transformer capacities, most of which can be
mitigated by upgrades or operational considerations.
• Transformers generally reach capacity limits prior to local transmission line segments.
• Available feeder capacity has been reduced in areas demonstrating load growth
requiring several new or upgraded distribution stations.
• A new Corrective Action Plan has been identified to address transient stability issues
identified in the Kettle Falls region.
• Three Corrective Action Plans continue to be promoted, specifically:
o South Spokane system reinforcement
o Spokane Valley transmission reinforcement
o Sunset Station rebuild
With respect to projected load growth, thermal-related issues are expected to appear while
voltages levels will be reduced, especially on the 115kV system. In addition, utility-scale
generation projects may also introduce significant system challenges.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1012 of 1105
Future planning scenarios will be impacted by proposed generation interconnections and their
inherent uncertainty. As with any other system device, interconnection projects will require
appropriate mitigation through either the interconnection or transmission service processes to
ensure that the existing transmission system performance is not negatively impacted.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1013 of 1105
II INTRODUCTION
The 2019-2020 Avista System Assessment (Planning Assessment) is a deliverable from
Phase 2 of a two-year process as defined in Avista’s Open Access Transmission Tariff (OATT)
Attachment K. The Planning Assessment identifies the Transmission System facility additions
required to reliably interconnect forecasted generation resources, serve the forecasted loads of
Avista’s Network Customers and Native Load Customers, and meet all other Transmission
Service and non-OATT transmission service requirements, including rollover rights, over a ten-
year planning horizon. The Planning Assessment process is open to all Interested Stakeholders, including, but not limited to, Transmission Customers, Interconnection Customers, and state authorities. The Western Electric Coordinating Council (WECC) facilitates interconnection wide planning and development of wide-area planning proposals.
The two-year planning process desired timeline is illustrated in Figure 1. The completion of Phase 2 includes providing the documented results of performing necessary technical studies. The state of the existing and future system is provided. Where the technical studies identified
performance issues, conceptual projects have been proposed. Projects identified from
previously posted planning assessments are listed as committed projects.

FIGURE 1: PLANNING ASSESSMENT TIMELINE.
Phase 3 of the process will follow the completion of the Planning Assessment. Phase 3
includes providing the Avista System Plan report to stakeholders. The Avista System Plan will include documentation of the electrical infrastructure plan with preferred solution options. The
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1014 of 1105
resulting project list will include additional information regarding projects and system
modifications developed through means other than the technical studies1.

1 Such other means may include, for example, generation interconnection or transmission service request study processes
under the OATT, or joint study team processes under NorthernGrid.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1015 of 1105
III TECHNICAL STUDY OVERVIEW
The Avista System Planning Assessment 2019 Study Plan outlines the process, assumptions
and technical studies used in the development of the Planning Assessment. The following is a
summary of the assumptions and technical studies performed. The complete Study Plan is
provided in Appendix I.
1 ASSUMPTIONS
1.1 System Representation
Computer simulation models are developed to represent the electric transmission and distribution system.
The transmission system models (Planning Cases or base cases) represent Avista’s Transmission Planner and Planning Coordinator areas as well as the regional Transmission System. The Planning Case development process outlined in the internal document TP-SPP-
04 – Data Preparation for Steady State and Dynamic Studies outlines the use of WECC
approved base cases and the modification of steady state and dynamic data as required to
represent existing facilities for the desired scenario. The resulting Planning Cases represent a
normal system condition (P0). All established pre-contingency operating procedures are
represented. Manual application of each operating procedure is followed in the process of developing each Planning Case.
Technical studies performed for the distribution system did not use detailed system models.
When distribution system models are used they are created by extracting data from several internal Avista sources.
All technical studies are performed assuming no projects are constructed within the planning horizon. After establishing a list of system deficiencies, new planned facilities and changes to existing facilities are represented to evaluate the impact to the deficiencies. Only potential
generation projects in Avista’s queue of generation interconnection requests that have
executed an Interconnection Agreement are modeled, along with corresponding upgrades, in
the models for technical studies.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1016 of 1105
1.2 Load Growth
Avista’s Balancing Authority Area (BAA) load peaked around 2,379MW in the winter of 2017 and 2,239MW in the summer of 2018. Figure 2 shows the BAA load historical seasonal peaks from 2008-2019 and the forecasted seasonal peaks for 2020-2030. The power factor of typical
loads at a station vary from 0.95 in the summer to unity in the winter. During light load
conditions, some loads may have leading power factor.

FIGURE 2: ACTUAL AND FORECASTED PEAK BALANCING AUTHORITY AREA LOAD.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1017 of 1105
1.3 Performance Criteria
The criteria used in evaluating the performance of the Transmission System are the current NERC Reliability Standards, WECC regional criterion and internal Avista policies, including the following. A summary of the Transmission System performance criteria is provided in the Study
Plan.
• TPL-001-WECC-CRT-3 – Transmission System Planning Performance
• TPL-001-4 – Transmission System Planning Performance Requirements
• FAC-010 – System Operating Limit Methodology for the Planning Horizon
• TP-SPP-01 – Avista Bulk Power System Planning Standards
Distribution system performance criteria is under development.
2 TECHNICAL STUDIES
The technical studies performed as part of the Planning Assessment includes the following:
• Steady state contingency analysis
• Spare equipment analysis
• Short circuit analysis
• Stability contingency analysis
• Voltage stability analysis
• Distribution capacity analysis
3 POINT OF CONTACT
A Point of Contact for questions regarding this Planning Assessment and the projects
described within it has been designated. Please contact the party named below with any
questions:
System Planning Department
PO Box 3727, MSC-16
Spokane, WA 99220
[e-mail]
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1018 of 1105
IV PROJECT AND ISSUE LIST
1 SUMMARY
The following section provides a list of Single System Projects. Single System Projects are
defined as projects necessary to ensure the reliability of the System and to otherwise meet the
needs of long-term firm transmission service and native load obligations in accordance with
Avista’s planning standards. Justification for each project listed can include condition based asset management, necessary to meet performance requirements, customer growth, and others. A summary of the Single System Projects is provided in Table 1. The cost estimate and schedule of each project is subject to change.
The listed Single System Projects justified as necessary to meet performance requirements categorized as Corrective Action Plans are also noted in Table 1. Corrective Action Plans address how performance requirements will be met where the technical studies have indicated
an inability of the System to meet the performance requirements of TPL-001. Corrective Action
Plans are specific projects developed to meet the criteria defined by NERC (TPL-001-4
R2.7.3).
All Single System Projects are subject to change or modification as necessary to
accommodate changes in load, generation, or other unforeseen system conditions.
TABLE 1: AVISTA TEN YEAR PROJECT LIST SUMMARY
Proposed
Initiative
Existing
Business
Case # Project Name Issue Mitigated
Date of
Operation
Big Bend System
Reinforcement
SDSC 47 Bruce Siding 115-13kV Sub Distribution Capacity
SDSR 11 Davenport 115-13kV Sub Age, condition and SCADA 2021
30 Little Falls 115kV Age and condition 2022
86
Sprague 115kV Substation - Minor
Rebuild Age and condition
TCC 6 Benton-Othello 115kV Line Sand Dunes 115kV bus outage 2020
50 Chelan-Stratford 115kV Line To be determined
TMR-AC 53 Devils Gap-Lind 115kV Line Age and condition
Cabinet Gorge GSU
Isolation PS 17 Cabinet Gorge 230kV Switchyard Unnecessary bus clearing 2021
Coeur d'Alene
System
Reinforcement
SDSC 48 Canfield 115-13kV Sub Distribution Capacity
7 Dalton 115-13kV Sub - Add 30MVA XFM Distribution Capacity 2020
75 Pleasantview 115-13kV Distribution Capacity
81 Rathdrum Distribution Distribution Capacity
SDSR 22 Huetter 115-13kV Sub - Expand Sub Distribution Capacity
82 Rathdrum 230/115kV Station Contingency 2024
TCC 1 Coeur d’Alene-Pine Creek 115kV Line Contingency and capacity 2019
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1019 of 1105
Proposed
Initiative
Existing
Business
Case # Project Name Issue Mitigated
Date of
Operation
East Coeur d'Alene
Lake System
Reinforcement
SDSC 27 Carlin Bay 115kV Sub Distribution Capacity 2023
10 St. Maries 115-24kV
Distribution capacity and
reliability
SDSR 27 O’Gara 115kV Switching Station Distribution Capacity 2023
TMR-AC 45 Benewah-Pine Creek 230kV Age and condition
TNC 27 Carlin Bay-O’Gara 115kV Line Distribution Capacity 2023
Idaho/Lewis County
System
Reinforcement
SDSR 60 Grangeville 115-13-34.5kV Age and condition 2023
65 Kooskia 115/13kV Age and condition 2023
Kettle Falls Stability 91 Addy - Kettle Falls Protection Scheme2 Kettle Falls OOS
Lewiston/Clarkston
System
Reinforcement
PS 61 Hatwai-Lolo #2 230kV Line Contingency and capacity 2024
SDSC 28
Lewiston Orchards Irrigation District 115-
13kV Sub Customer requested 2021
90 Wheatland 115-13V Sub Distribution Capacity
SDSR 36 Tenth & Stewart 115-13kV Distribution Capacity
19
Bryden Canyon 115kV Sub (Replace
Equip) Load service and reliability 2022
56 Dry Gulch Customer requested 2020
21 Lolo 230kV Station Age, condition and capacity 2023
78 Pound Lane 115-13kV Age and condition
TMR-AC 66 Lolo-Oxbow 230kV Line Age and condition 2025
Metro Station
Rebuild SDSR 20 Metro 115-13V Sub Age and condition 2023
TMR-AC 5 Metro-Post Street 115kV Line Age and condition 2020
76 Post Street-Third & Hatch 115kV Line Age and condition 2021
North Spokane
System
Reinforcement
PS 42 Beacon-Bell-F&C-Waikiki Reconfiguration Contingency and capacity
69 Mead-Colbert-Milan 115kV Line Contingency and capacity
SDSC 33 Florida & Dalke 115-13kV Sub Distribution Capacity 2024
23 Hawthorne 115kV Sub Contingency and capacity 2024
26 Midway 115/13kV Sub Distribution Capacity 2023
88 Waikiki - Add Capacity Distribution Capacity 2021
89 Waikiki-Mead 115/13kV Sub Distribution Capacity 2023
SDSR 67 Lyons & Standard 115-13kV Distribution Capacity
35 Northwest 115-13kV Sub Age and condition 2021
TNC 33 Transmission to Serve Hillyard Sub Distribution capacity
23 Transmission to Serve Hawthorne Sub Distribution capacity
62 Indian Trail-Waikiki 115kV Line Contingency and capacity
69 Mead-Colbert-Milan 115kV Line Contingency and capacity 2024
2 Corrective Action Plan
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1020 of 1105
Proposed
Initiative
Existing
Business
Case # Project Name Issue Mitigated
Date of
Operation
Palouse System
Reinforcement
SDSC 49 Center Street 115-13V Sub Distribution Capacity 2023
29 M/P State Line 115-13V Sub Distribution Capacity
87 Tamarack 115/13kV Sub Distribution Capacity
SDSR 71 Moscow City 115kV Sub Age and condition
72
N. Moscow 115kV Station: Add
Transformer Distribution Capacity
74
Palouse Transformation: Add Auto at
Moscow or Shawnee Contingency
77 Potlatch 115/13kV Age and condition
Protection System
Upgrade for PRC-002 PS 79 PRC-002 Protection System Upgrade Compliance 2022
Rattlesnake Flat
Wind Farm PS 2
Rattlesnake Flat 115kV Wind Farm
Project Customer requested 2020
Saddle Mountain
Integration PS 9
Saddle Mountain 230/115kV Sub (Phase
1) Contingency and capacity 2020
13
Saddle Mountain 230/115kV Sub (Phase
2) Contingency and capacity 2021
Sandpoint System
Reinforcement
SDSR 32 Bronx 115/21kV Substation Distribution Capacity 2024
TCC 83 RAT-SPI or ALB-SPI 115kV Line Contingency 2024
Silver Valley System
Reinforcement
SDSC 70 Mission 115kV Sub Age and condition
SDSR 46 Big Creek 115kV Sub Age and condition
TMR-AC 73 Noxon-Pine Creek 230kV Age and condition 2022
South Spokane
System
Reinforcement
PS 42 Beacon 230kV Sub Contingency and capacity
85
Spokane West of Beacon - New 230kV
Transformation3 Contingency and capacity 2025
SDSC 54 Downtown East 115-13kV Sub Distribution Capacity
55 Downtown West 115-13kV Sub Distribution Capacity 2023
4 Southeast 115-13kV Distribution Capacity 2019
SDSR 52 College & Walnut 115kV Sub Age and condition
84 Ross Park 115kV Sub Age and condition
TCC 39 9CE-Sunset 115kV Line Contingency and capacity 2023
44 Beacon-Ross Park 115kV Line Age and condition 2020
Spokane Valley
Transmission
Reinforcement
SDSC 63 Irvin 115/13kV Sub Distribution Capacity 2021
SDSR 41 Barker 115/13kV Substation Distribution Capacity
51 Chester 115-13kV Sub Age and condition
SVTR 14
BEA-BLD #2 115 - Upgrade 314MVA
(TLD4)
Line section outage issues,
motor starting support at IEP
and reliability 2021
3 Corrective Action Plan
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1021 of 1105
Proposed
Initiative
Existing
Business
Case # Project Name Issue Mitigated
Date of
Operation
12 Irvin 115kV Switching Station4 Contingency and capacity 2021
TCC 43 Beacon-Boulder #1 115kV Line Contingency and capacity 2021
Stevens/Ferry
County System
Reinforcement
SDSC 37 49 Degrees North 115kV Sub Distribution Capacity
34 Valley 115kV Sub Age and condition 2022
TCC 40 Addy-Devils Gap 115kV Line Contingency and capacity 2020
Sunset Station
Rebuild SDSR 15 Sunset 115kV Sub5 Age, condition and reliability 2021
West Plains System
Reinforcement
PS 58 Garden Springs 115/13kV Substation Contingency and capacity 2023
59 Garden Springs 230kV Substation Contingency and capacity
SDSC 16 Flint Road 115/13kV Sub Distribution Capacity 2022
18 Four Lakes - Add Cap Bank P6 low voltage
68 McFarlane 115/13kV Sub Distribution Capacity
TBD 31 Melville Switching Station
Customer requested,
contingency
Westside Station
Rebuild PS 8 Westside 230/115kV Sub (Phase 1-4) Contingency and capacity 2022

4 Corrective Action Plan
5 Corrective Action Plan
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1022 of 1105
2 IDENTIFIED SYSTEM PROJECTS
Following is a summary of identified system issues, mitigations considered and
recommendations.
2.1 Big Bend System Reinforcement
The Davenport, Little Falls and Sprague stations in the Big Bend area have been identified as
a concern due to age and condition. Additionally, the age and condition of the Devil’s Gap – Lind 115kV Transmission Line has been identified as a concern due to age and condition.
The Chelan – Stratford 115kV Transmission Line has demonstrated overload conditions due to
local hydro generation during contingencies scenarios. The transmission line segments
overloaded are 0.38 miles of 19#8 CW and 33.89 miles of 250 CU conductor with a rating of
78.3 MVA at 40°C.
Mitigation considered
The condition of identified stations and transmission lines due to age and condition should be
analyzed to determine the scope of rebuilding the assets or target specific equipment replacement.
Recommendations
• Rebuild Davenport, Little Falls, and Sprague stations.
• Minor rebuild of Devils Gap – Lind 115kV Transmission Line.
• Utilize operating procedure to reduce local hydro generation for contingencies impacting
Chelan – Stratford 115kV Transmission Line.
2.2 Cabinet Gorge GSU Isolation
The design to integrate the Cabinet Gorge hydro facility into the 230kV Western Montana
Hydro transmission system did not include 230kV breakers to isolate the generation from the
transmission system. This resulted in one zone of protection encapsulating both the Generator
Step-Up (GSU) transformers and the 230kV bus. The deficiency with this design is that it is not selective enough and drops all 230kV lines, the Cabinet 230/115kV autotransformer and all Cabinet Gorge generation for issues with the either GSU.
Studies have identified the following contingency issue:
• Loss of a single Cabinet Gorge GSU (P1.3) results in the loss of up to 240MW of
generation, two 230kV lines, and a 230/115kV autotransformer.
Mitigation considered
• Full rebuild of Cabinet Substation.
• Modify the existing Cabinet Substation with the addition of high-side GSU circuit
breakers.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1023 of 1105
• Building a new switching station west of the existing Cabinet Substation to incorporate
breakers and loop in the Lancaster – Noxon 230kV Transmission Line.
Recommendations
• A reliability upgrade to Cabinet substation consisting of a new 230kV breaker for each GSU, relocating two termination towers and adding new 230kV bus. Upgrades will require updates to GSU and bus relay protection.
2.3 Coeur d'Alene System Reinforcement
The Coeur d’Alene area is served by two 230/115kV autotransformers and a single 115kV transmission line. The Coeur d’Alene area is connected by one additional 115kV transmission line that has historically been operated normally open. The autotransformers along with the 115kV transmission lines feeding Coeur d’Alene load may overload for multiple contingency
events during moderate to heavy loading during all seasons.
Studies have identified the following contingency issues:
• Loss of the Rathdrum 115kV east bus (P2.2) or a breaker failure on the Rathdrum
115kV east bus (P2.3) may result in an overload of a 115kV transmission line.
• Loss of the Pine Street – Rathdrum 115kV Transmission Line followed by the loss of a
230/115kV autotransformer (P6) may result in an overloaded 230/115kV
autotransformer.
• Loss of a Rathdrum 230/115kV autotransformer followed by the loss of a 230/115kV
autotransformer (P6) may result in voltage collapse in the Coeur d’Alene area. This
results in the loss of up to 140MW of generation and 275MW of load.
• A Rathdrum 115kV bus tie breaker failure during any season results in the loss of up to
140MW of generation and 275MW of load in the Coeur d’Alene area.
Load growth in the Coeur d’Alene area has contributed to heavy loaded distribution facilities. The following stations have feeders which have exceeded 80% of their applicable facility ratings: Appleway, Dalton, Huetter, Post Falls, Prairie and Idaho Road. Anticipated load growth will increase the feeder loading and reduce necessary operational capacity.
The Prairie Station in the Coeur d’Alene area has been identified as a concern due to age and
condition.
Mitigation considered
Transmission system contingency issue mitigation alternatives include the following:
• Operate the Coeur d’Alene – Pine Creek 115kV Transmission Line normally closed and revert back to the original 115kV transmission line configuration between Coeur d’Alene and Spokane Valley.
o Requires upgrading the transmission lines connecting Coeur d’Alene and
Spokane Valley.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1024 of 1105
• Operate the Coeur d’Alene – Pine Creek 115kV Transmission Line normally closed and
build a new switching station near the crossing of Chase Road and Poleline Avenue.
• Build a new 230/115kV substation between Boulder Substation and Rathdrum
Substation and integrate the existing 115kV transmission lines into this new substation.
• Build a new 230/115kV substation southeast of Coeur d’Alene with a 230kV tie to Pine
Creek and integrate the existing 115kV transmission lines into the new substation.
Upgrade existing distribution stations with additional feeder capacity including: Dalton, Pleasantview, Rathdrum, Huetter, and Prairie.
The condition of identified stations due to age and condition should be analyzed to determine the scope of rebuilding the assets or target specific equipment replacement.
Recommendations
• The transmission system contingency mitigation project’s specific scope and impact will
be evaluated by the responsible parties within Avista to assist in the development of a
coordinated business and implementation plan that will be presented to the Engineering
Roundtable (ERT) for approval, prioritization, and deployment.
• Rebuild Pleasantview and Prairie stations.
2.4 East Coeur d'Alene Lake System Reinforcement
Forecasted load growth along the east side of Coeur d’Alene Lake is expected to cause the
total load to exceed the capability of the existing 13.2 kV distribution system in the area.
Feeder protection coordination and voltage regulation are not able to meet necessary
performance requirements. Cold load pickup will cause protection devices to function during
moderate to heavy loading levels.
Feeder loading from the St. Maries Station are near capacity. Recent growth in the area
including a large industrial customer with 2300 horsepower of motor load will further increase
equipment loading and reduce operational flexibility to maintain and back up feeders. The lack
of Supervisory Control and Data Acquisition (SCADA) at St. Maries Station creates safety
concerns and does not allow necessary situational awareness of the equipment status.
The Benewah – Pine Creek 230kV Transmission Line has been identified as a concern due to
age and condition.
Mitigation considered
• Construct new Carlin Bay Station with a 13 mile radial 115kV transmission line to a
rebuilt O’Gara Station.
• Convert area distribution system to 25kV.
• Upgrade St. Maries Station with fourth feeder and addition of SCADA.
• Rebuild the Benewah – Pine Creek 230kV Transmission Line
Recommendations
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1025 of 1105
• Construct new Carlin Bay Station with a 13 mile radial 115kV transmission line to a
rebuilt O’Gara Station.
• Upgrade St. Maries Station with fourth feeder and addition of SCADA.
2.5 Idaho/Lewis County System Reinforcement
The Grangeville and Kooskia stations in the Idaho/Lewis county area have been identified as a
concern due to age and condition.
Mitigation considered
The condition of identified stations due to age and condition should be analyzed to determine
the scope of rebuilding the assets or target specific equipment replacement.
Recommendations
• Rebuild Grangeville and Kooskia stations
2.6 Kettle Falls Stability
Implementation of a high speed, communication aided tripping scheme on the Addy – Kettle
Falls 115kV Transmission Line is necessary to improve stability performance of the Kettle Falls
generation facility. Stability contingency analysis indicates an inability of the System to meet
the performance requirements in requirement R4.1.1 of TPL-001-4.
Studies have identified the following contingency issue:
• The Kettle Falls generator can become unstable if a time delayed three phase fault occurs on the Addy – Kettle Falls 115kV Transmission Line near Addy.
Mitigation considered
• This is a vetted project. Refer to past studies for mitigation options.
Recommendations
• The identified contingency issues will require a Corrective Action Plan.
• Modification of the Addy – Kettle Falls 115kV Transmission Line Protection System to
include a communication aided protection scheme. A new communication path is
required between Addy and Kettle Falls stations. Upgrades and setting changes to
relays at BPA’s Addy Substation and Avista’s Kettle Falls Substation are also required
to implement Avista’s standard communication aided protection schemes.
2.7 Lewiston/Clarkston System Reinforcement
The existing 230kV system and underlying 115kV lines in the Lewiston/Clarkston area may
overload during summer loading and high transfers south on the Idaho – Northwest (Path 14)
cut plane for multiple contingency events. Planned or forced 230kV outages in the
Lewiston/Clarkston area require a radial configuration of the 115kV system, arming RAS and/or reducing transfers on the Idaho – Northwest or West of Hatwai cut planes.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1026 of 1105
Studies have identified the following contingency issues:
• Loss of Dry Creek – North Lewiston 230kV Transmission Line followed by the loss of a 230kV transmission line (P6) may result in an overload of multiple 115kV transmission lines.
• Loss of Hatwai – Lolo 230kV Transmission Line followed by the loss of a 230/115kV autotransformer or any of two 230kV transmission lines (P6) may result in an overload
of multiple 115kV transmission lines.
• Loss of the North Lewiston 230/115 #1 Transformer followed by the loss of a 230kV transmission line (P6) may result in an overloaded 115kV transmission line.
Load growth in the Lewiston/Clarkston area has contributed to heavy loaded distribution
facilities. The following stations have feeders which have exceeded 80% of their applicable
facility ratings: Lolo, Critchfield, and Tenth & Stewart. Anticipated load growth will increase the
feeder loading and reduce necessary operational capacity.
The South Lewiston, Lolo and Pound Lane stations in the Lewiston/Clarkston area have been
identified as a concern due to age and condition. Additionally, the age and condition of the Lolo
– Oxbow 230kV Transmission Line has been identified as a concern due to age and condition.
Mitigation considered
Transmission system contingency issue mitigation alternatives include the following:
• Rebuild the overloaded 115kV transmission lines that were identified in the study.
• Rebuild South Lewiston substation into a switching station and close all three lines into
the new station.
o Reduces contingency overloads, but does not correct overload issues.
• Build a new second Hatwai – Lolo 230kV transmission line to either connect into Lolo
Substation or bypass the Lolo Substation and connect directly to Oxbow Substation.
This may require a new transmission line terminal at Lolo Station and a request for
interconnection at BPA’s Hatwai Station.
Rebuild existing distribution stations with additional feeder capacity.
The condition of identified stations due to age and condition should be analyzed to determine
the scope of rebuilding the assets or target specific equipment replacement.
Recommendations
• The transmission system contingency mitigation project’s specific scope and impact will be evaluated by the responsible parties within Avista to assist in the development of a coordinated business and implementation plan that will be presented to the Engineering Roundtable (ERT) for approval, prioritization, and deployment.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1027 of 1105
• Rebuild Tenth & Stewart and Pound Lane stations and targeted equipment replacement
at Lolo Station.
• Construct new Bryden Canyon and Wheatland stations.
• Rebuild portions of the Lolo – Oxbow 230kV Transmission Line and evaluate priorities
of other 230kV transmission line rebuilds.
2.8 Metro Station Rebuild
Metro Station dates to the mid-1970s. Switchgear is the worst condition on the system. Much of the major equipment in this station is now unsupported by the manufacturer. Legacy oil
tanks beneath the site pose an environmental problem and limit modifications to upgrade the
existing station. Underground transmission cables to this site are in need of replacement.
Transformer/switchgear spares are unavailable/difficult to install in an outage scenario.
Various other condition issues, such as the 115kV breakers, insulators, and panel house, also
exist at this site.
Additionally, the age and condition of the Metro – Post Street and Post Street – Third & Hatch 115kV transmission lines has been identified as a concern due to age and condition.
Mitigation considered
• Rebuild Metro Station by replacing existing equipment with new.
• Rebuild Metro Station with new equipment in an improved configuration.
• Construct a new station on a new site to replace the existing Metro Station.
• Replace existing transmission cable on the Metro – Post Street and Post Street – Third & Hatch 115kV transmission lines.
Recommendations
• Construct a new station on a new site to replace the existing Metro Station.
• Replace existing transmission cable on the Metro – Post Street and Post Street – Third
& Hatch 115kV transmission lines.
2.9 North Spokane System Reinforcement
Avista’s Beacon and BPA’s Bell substations are connected by two 115kV lines, either of which may overload for multiple contingency events during moderate to heavy loading during all
seasons. Note that the additional autotransformer capacity, which is planned for the South
Spokane area, will increase the overloads identified in these results.
Studies have identified the following contingency issues:
• A Beacon 115kV bus tie breaker fault (P2.4) may result in an overload of multiple 115kV
transmission lines.
• Loss of the Beacon – Bell 115kV Transmission Line followed by the loss a 230/115kV
autotransformer (P6) may result in an overload of multiple 115kV transmission lines.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1028 of 1105
• Loss of the Beacon – Northeast 115kV Transmission Line followed by the loss a
230/115kV autotransformer (P6) may result in an overloaded 115kV transmission line.
• Loss of the Bell 230/115kV #6 Transformer followed by the loss of any of two 115kV
transmission lines (P6) may result in an overloaded 115kV transmission line.
• Loss of the Bell – Northeast 115kV Transmission Line followed by the loss a 230/115kV
autotransformer (P6) may result in an overloaded 115kV transmission line.
• Loss of the Francis & Cedar – Ross Park 115kV Transmission Line followed by the loss of a 115kV transmission line (P6) may result in an overloaded 115kV transmission line.
Load growth in the North Spokane area has contributed to heavy loaded distribution facilities.
The following stations have feeders which have exceeded 80% of their applicable facility ratings: Colbert, Francis & Cedar, Waikiki and Mead. Anticipated load growth will increase the feeder loading and reduce necessary operational capacity.
The Northwest Station in the North Spokane area has been identified as a concern due to age and condition.
Mitigation considered
Transmission system contingency issue mitigation alternatives include the following:
• Rebuild the overloaded 115kV transmission lines that were identified in the study.
o This requires the rebuild of the Beacon – Bell, Beacon – Northeast, Bell –
Northeast, and Beacon – Francis & Cedar 115kV transmission lines.
• Add Remedial Action Scheme (RAS) to drop load in the BPA area.
o Solution only solves BPA related issues, but does not correct remaining Avista related transmission line loading issues.
• Build a new 115kV transmission line from Indian Trail substation to Waikiki substation
and add breaker positions to both stations.
o Does not correct all identified 115kV transmission line overloads.
• Loop the Beacon – Francis & Cedar 115kV transmission line into Bell.
Rebuild existing distribution stations with additional feeder capacity and construct new
distribution stations.
The condition of identified stations due to age and condition should be analyzed to determine
the scope of rebuilding the assets or target specific equipment replacement.
Recommendations
• The transmission system contingency mitigation project’s specific scope and impact will
be evaluated by the responsible parties within Avista to assist in the development of a
coordinated business and implementation plan that will be presented to the Engineering
Roundtable (ERT) for approval, prioritization, and deployment.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1029 of 1105
• Rebuild Northwest Station.
• Construct new Florida & Dalke, Hawthorne and Midway stations.
• Construct new 115kV infrastructure to the north of Spokane to interconnect Avista
distribution stations into Avista’s transmission system.
2.10 Palouse System Reinforcement
The Palouse area is served by two 230/115kV autotransformers and a single 115kV line. The Palouse is connected by four additional 115kV transmission lines that have historically been operated normally open. These autotransformers along with the 115kV transmission lines
feeding Palouse load may overload for multiple contingency events during moderate to heavy
loading (all seasons).
Studies have identified the following contingency issues:
• Loss of a Palouse area 230/115kV autotransformer followed by the loss of a 230/115kV
autotransformer (P6) may result in voltage collapse in the Palouse area. This results in
the loss of up to 186MW of load.
• Loss of the Moscow – South Pullman 115kV Transmission Line followed by the loss a
230/115kV autotransformer (P6) may result in an overloaded 115kV transmission line.
• Loss of the Moscow – Terre View 115kV Transmission Line followed by the loss a
230/115kV autotransformer (P6) may result in an overloaded 115kV transmission line.
Load growth in the Palouse area has contributed to heavy loaded distribution facilities. The
following stations have feeders which have exceeded 80% of their applicable facility ratings: Turner. Anticipated load growth will increase the feeder loading and reduce necessary operational capacity.
The Moscow City and Potlatch stations in the Palouse area have been identified as a concern due to age and condition.
Mitigation considered
Transmission system contingency issue mitigation alternatives include the following:
• Add a new position at Moscow and extend the Moscow City – North Lewiston 115kV
Transmission Line into Moscow 230 Station. Operate with Moscow City normally fed
from this line, with the auto-throwover to the Moscow – South Pullman 115kV
Transmission Line.
• Add a second 230/115kV autotransformer at Moscow or Shawnee stations.
• Build a new 230/115kV station east of Pullman and integrate the existing 115kV
transmission lines into the new station.
Construct new and rebuild existing distribution stations with additional feeder capacity.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1030 of 1105
The condition of identified stations due to age and condition should be analyzed to determine
the scope of rebuilding the assets or target specific equipment replacement.
Recommendations
• The transmission system contingency mitigation project’s specific scope and impact will be evaluated by the responsible parties within Avista to assist in the development of a coordinated business and implementation plan that will be presented to the Engineering
Roundtable (ERT) for approval, prioritization, and deployment.
• Construct new Center Street, State Line and Tamarack stations.
• Rebuild Moscow City and Potlatch stations.
2.11 Protection System Upgrade for PRC-002
NERC reliability standard PRC-002-2 defines the disturbance monitoring and reporting
requirements to have adequate data available to facilitate analysis of Bulk Electric System
(BES) Disturbances. The methodology of Attachment A of the NERC standard was performed to identify the affected buses within the Avista BES. The Protection Systems must be capable of recording electrical quantities for each BES Elements it owns connected to the BES buses identified.
The present Protection Systems are either electromechanical or first generation relays not
capable of meeting the NERC PRC-002-2 standard requirements of fault recording.
Implementation is a phased approach with 50% compliant within four years and fully compliant within six years of the July 1, 2016 effective date. There is a total of 49 affected terminals.
Mitigation considered
Upgrade the existing Protection Systems on various 230kV and 115kV terminals to Fault Recording (FR) capability per PRC-002 requirements at Beacon, Boulder, Rathdrum, Cabinet Gorge, North Lewiston, Lolo, Pine Creek, Shawnee and Westside.
Recommendations
• Complete Protection System Upgrades for PRC-002 Business Case.
2.12 Rattlesnake Flat Wind Farm
An Interconnection Customer (Project #49) has requested interconnection of a new Wind
Power Plant (WPP) generation facility located southeast of Lind, Washington. The customer
has chosen an interconnection to Avista’s Lind - Washtucna 115kV Transmission Line,
approximately 4.5 miles south of the Lind Station, requiring a new 115kV Neilson Station at the
Point of Interconnection (POI) with a 115kV line position dedicated for the Interconnection
Customer. Project #49 will have an aggregate nameplate capacity of 144MW and will consist
of seventy-two (72), Vestas V110, 2.0MW Wind Turbine Generators (WTG).
Mitigation considered
• Rebuild Lind Station to accept the generator lead line with the POI at Lind Station.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1031 of 1105
• Construct new Neilson Station as the POI and rebuild the transmission line from Neilson
to Lind.
Recommendations
• Construct network upgrades and direct assigned facilities according to Project #49 Facilities Study.
2.13 Saddle Mountain Integration
In the fall of 2013, Grant employees contacted Avista System Planning about performance issues within Grant’s system that are exacerbated by Avista’s load in the Othello area. The issue was escalated to ColumbiaGrid through the Regional Planning process. It was identified through this process and Avista System Planning that the system performance analysis indeed indicates an inability of the System to meet the performance requirements P1, P2 and P6
categories in Table 1 of NERC TPL-001-4 in current heavy summer scenarios, and P6
categories in heavy winter scenarios.
Studies have identified the following contingency issues:
• Loss of the Benton – Othello SS 115kV line followed by the loss of the Sand Dunes –
Warden 115kV line during summer loading may overload the Larson – Sand Dunes –
Warden 115kV line (up to 116%).
• Loss of the Larson – Sand Dunes – Warden 115kV line, followed by load restoration
(Wheeler to Basset Jct. 115kV line section outage shows worst performance), followed
by the loss of the Sand Dunes – Warden 115kV line during spring and summer loading will overload the Benton – Othello SS 115kV line and result in voltage collapse in the Othello area (drops up to 168MW).
Mitigation considered
• Construct Saddle Mountain Station, one new 115kV transmission line from Saddle
Mountain to Othello City, and a new Othello City Station.
• Build new 115kV transmission line into the area from the Stratford area.
• Close normally open points to the east of the area.
Recommendations
• Complete Saddle Mountain Project (Phase 1 and Phase 2).
2.14 Sandpoint System Reinforcement
Load growth around Sandpoint is expected to cause the total load to exceed the capability of the existing 20.8 kV distribution system in the area. The existing Sandpoint Station distribution
transformers are unique to Avista’s system. Mobile transformers cannot be used to replace a failed transformer at this site. Continued load growth increases the risk of reliability serving
customers in the area with potential equipment failure.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1032 of 1105
Previous transmission system studies have shown P6 contingency performance issues when
two of the three transmission lines into the Sandpoint area are out of service. The issues
observed were primarily low voltages during heavy winter loading. BPA has also documented
in their 2019 System Assessment Summary Report observed performance issues in the area.
Mitigation considered
Rebuild the Bronx Station to provide distribution service to the area.
Construct new 115kV transmission line from Rathdrum or Albeni Falls towards Sandpoint.
Recommendations
• Rebuild the Bronx Station to provide distribution service to the area.
• Perform a detailed project analysis to determine risks and mitigations to low voltages in the area.
2.15 Silver Valley System Reinforcement
The Mission and Big Creek stations in the Silver Valley area have been identified as a concern due to age and condition. The feeder served by Mission Station has protection selectivity concern due to the feeder trunk extending two distinctly different directions.
The age and condition of the Noxon – Pine Creek 230kV Transmission Line has been
identified as a concern due to age and condition.
Mitigation considered
The condition of identified stations and transmission lines due to age and condition should be
analyzed to determine the scope of rebuilding the assets or target specific equipment replacement.
Recommendations
• Rebuild Big Creek station.
• Upgrade Mission Station with a second feeder position.
• Minor rebuild of Noxon – Pine Creek 230kV Transmission Line.
2.16 South Spokane System Reinforcement
The Spokane area is served by five 230/115kV autotransformers. These autotransformers
along with the 115kV transmission lines feeding Spokane load may overload for multiple
contingency events during moderate to heavy loading (all seasons). Existing mitigation
projects (Ford – Devils Gap 115kV Transmission Line section rebuild, Irvin Switching Station, capacity at Westside) help reduce the amount of overloading, but do not correct known contingency issues. Steady state contingency analysis indicates an inability of the System to meet the performance requirements in requirement R3.1 of TPL-001-4 for the Beacon 115kV tie breaker failure.
Studies have identified the following contingency issues:
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1033 of 1105
• A Beacon 230kV or 115kV bus tie breaker fault (P2.4) may result in an overloaded
230/115kV autotransformer and multiple 115kV transmission lines.
• A Ninth & Central 115kV bus tie breaker fault (P2.4) may result in an overloaded 115kV
transmission line.
• Loss of an Addy – Bell 115kV Transmission Line section followed by the loss of any of
three 230/115kV autotransformers (P6) may result in an overloaded 230/115
transformer and multiple 115kV transmission lines.
• Loss of any of three 230/115kV autotransformers followed by the loss of a remaining
230/115kV autotransformer (P6) may result in an overloaded 230/115kV
autotransformer and multiple 115kV transmission lines.
• Loss of either Beacon – Ninth & Central 115kV transmission line followed by the loss of
any of three 115kV transmission lines (P6) may result in an overload of multiple 115kV
transmission lines.
• Loss of the Bell – Westside 230kV Transmission Line followed by the loss of any of three 230/115kV autotransformers (P6) may result in an overloaded 230/115
transformer.
• Loss of the College & Walnut – Westside 115kV Transmission Line followed by the loss of any of two 115kV transmission lines (P6) may result in an overload of multiple 115kV transmission lines.
The College & Walnut and Ross Park stations in the Spokane area have been identified as a
concern due to age and condition.
The Beacon – Ross Park 115kV Transmission Line has been identified as a concern due to
age and condition.
Mitigation considered
Transmission system contingency issue mitigation alternatives include the following:
• Increase the capacity of the Bell #6 230/115kV Transformer.
o Does not correct remaining Spokane area 230/115kV transformer loading issues or resolve 115kV line loading issues feeding the West Plains area.
• Rebuild Beacon to a more reliable breaker arrangement or add a series breaker to both
the bus tie breakers.
o Does not correct remaining Spokane area 230/115kV autotransformer loading
issues or resolve 115kV transmission line loading issues feeding the West Plains
area.
• Rebuild the overloaded 115kV transmission lines
o Does not correct Spokane area 230/115kV autotransformer loading issues.
• Loop the Beacon – Francis & Cedar 115kV Transmission Line into Bell Station.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1034 of 1105
o Does not correct Spokane area 230/115kV autotransformer loading issues.
• Build a new 115kV transmission line from Westside Station to the West Plains area or to the Spokane downtown area.
o Does not correct Spokane 230/115kV autotransformer loading issues.
• Add a new 230/115kV transformation at Ninth & Central Station and associated 230kV
transmission lines.
The condition of identified stations and transmission lines due to age and condition should be analyzed to determine the scope of rebuilding the assets or target specific equipment replacement.
Recommendations
• The identified contingency issues will require a Corrective Action Plan.
• The transmission system contingency mitigation project’s specific scope and impact will
be evaluated by the responsible parties within Avista to assist in the development of a
coordinated business and implementation plan that will be presented to the Engineering
Roundtable (ERT) for approval, prioritization, and deployment.
• Construct new Downtown East and Downtown West stations.
• Rebuild College & Walnut and targeted equipment replacement at Ross Park stations.
• Rebuild the Beacon – Ross Park 115kV Transmission Line.
2.17 Spokane Valley Transmission Reinforcement
The Spokane Valley Transmission Reinforcement project improves transmission system performance by networking the 115kV transmission lines in the area together at Irvin and Opportunity stations. This reinforcement was necessitated by area load growth along with motor starting voltage issues resulting from the integration of two 25MW synchronous motors at Inland Empire Paper in 2007. Steady state contingency analysis indicates an inability of the
System to meet the performance requirement in TPL-001-4 R3.1 for the Boulder 115kV tie
breaker failure.
Studies have identified the following contingency issues:
• Loss of a Liberty Lake – Otis Orchards 115kV Transmission Line section or a Nelson – Ninth & Central 115kV Transmission Line section (P2.1) can load the remaining transmission line to its thermal limit. This has resulted in transferring all load growth to adjacent transmission facilities.
• A Boulder 115kV bus tie breaker fault (P2.4) may result in an overloaded 115kV
transmission line above 125% of rating.
• Loss of the Beacon – Ross Park 115kV Transmission Line followed by the loss of any of
two 115kV transmission lines (P6) may result in an overloaded 115kV transmission line.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1035 of 1105
• Loss of the College & Walnut – Westside 115kV Transmission Line followed by the loss
of any of two 115kV transmission lines (P6) may result in an overload of multiple 115kV
transmission lines.
• Loss of the Opportunity – Otis Orchards 115kV Transmission Line followed by the loss
of any of two 115kV transmission lines (P6) may result in an overloaded 115kV
transmission line.
Mitigation considered
• This is a vetted project. Refer to past studies for mitigation options.
Recommendations
• The identified contingency issues will require a Corrective Action Plan.
• Complete Spokane Valley Transmission Reinforcement Business Case including installation of the Irvin Station.
• Increase distribution capacity at Barker Station and add distribution facilities to Irvin Station.
• Rebuild Chester Station.
2.18 Stevens/Ferry County System Reinforcement
The Valley Station in the Stevens/Ferry county area has been identified as a concern due to
age and condition.
The 49 Degrees North Ski Resort has an expansion plan which will exceed the capacity of the existing distribution system. The existing distribution is being reinforced to accommodate the planned expansion, but there is limited additional capacity.
Mitigation considered
The condition of identified stations due to age and condition should be analyzed to determine the scope of rebuilding the assets or target specific equipment replacement.
Construct a new 49 Degrees North distribution station to serve additional load growth.
Expand Chewelah Station with a new transformer and dedicated feeder.
Recommendations
• Rebuild Valley Station.
• Construct a new 49 Degrees North distribution station when customer request is
received.
2.19 Sunset Station Rebuild
The existing circuit breakers at the station do not have sufficient short circuit interrupting capability to interrupt close in faults on the connected transmission lines. The available fault
current increases with the necessary transmission system expansion to address other system
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1036 of 1105
deficiencies (i.e. Westside transformer replacement). Short circuit analysis indicates an
inability of the System to meet the performance requirements in requirement R2.8 of TPL-001-
4.
Mitigation considered
Analysis of potential reconfiguration of the station concluded the station should be rebuilt with five transmission line terminals to match the existing station. The analysis reviewed potential reconfigurations with the objective of minimizing the station size. All configurations considered did not provide desired transmission system performance or reliability.
Recommendations
• The identified issues will require a Corrective Action Plan.
• The Sunset Station has been identified for a complete rebuild.
2.20 West Plains System Reinforcement
The West Plains and Sunset area (up to 245MW) is served by (4) 115kV transmission lines, which may overload for multiple contingency events during summer loading. Existing mitigation projects (Garden Springs – Sunset 115kV Transmission Line rebuild and the Ninth & Central –
Sunset 115kV Transmission Line rebuild) help reduce the amount of overloading, but do not
correct known contingency issues.
Studies have identified the following contingency issues:
• Loss of the Ninth & Central – Sunset 115kV Transmission Line followed by the loss of
any of four 115kV transmission lines (P6) may result in an overload of multiple 115kV
transmission lines.
• Loss of the Sunset – Westside 115kV Transmission Line followed by the loss of any of
six 115kV transmission lines (P6) may result in an overload of multiple 115kV
transmission lines.
Load growth in the West Plains area has contributed to heavy loaded distribution facilities. The
following stations have feeders which have exceeded 80% of their applicable facility ratings:
Airway Heights. Anticipated load growth will increase the feeder loading and reduce necessary
operational capacity.
Mitigation considered
Transmission system contingency issue mitigation alternatives include the following:
• Rebuild the overloaded 115kV transmission lines that were identified in the study.
o This requires the rebuild of the College & Walnut – Westside, Francis & Cedar –
Northwest, Ninth & Central – Third & Hatch, Post Street – Third & Hatch, Ross
Park – Third & Hatch and Sunset – Westside 115kV transmission lines.
• Build a new seven mile 115kV transmission line from Westside Station to the West
Plains area.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1037 of 1105
• Add a new 230/115 transformation at Garden Springs and associated 230kV lines.
Construction of new distribution stations and related 115kV transmission line integration will support the anticipated load growth.
Recommendations
• The transmission system contingency mitigation project’s specific scope and impact
was evaluated by the responsible parties within Avista to assist in the development of a
coordinated business and implementation plan that was presented to the Engineering
Roundtable (ERT), approved and prioritized for deployment.
• Construct new Flint Road, McFarlane, and Melville stations with transmission line
integration according to the West Plains Reinforcement Plan.
2.21 Westside Station Rebuild
Westside Substation was the last remaining Spokane area substation with 125 MVA rated
autotransformers. In past studies, the Westside autotransformers would overload for multiple
contingency events during moderate to heavy loading in all seasons. The Westside
autotransformers are being upgraded to two 250 MVA rated units. Planned reliability
improvements to both the 115kV and 230kV bus arrangements are also in this scope, which
were required due to increased fault duty from the larger transformers.
Refer to previous studies for identified contingency issues that nucleated the Westside
autotransformer upgrade.
The Westside Station is currently being rebuilt, with completion planned for fall of 2022. The construction sequence has resulted in the following temporary contingency issues:
• Loss of the Westside 115kV southwest bus (P2.2) or a breaker failure on the Westside 115kV southwest bus (P2.3) may result in an overload of multiple 115kV transmission lines.
Mitigation considered
• This is a vetted project, refer to past studies for mitigation options.
Recommendations
• Complete the installation of the second 250 MVA autotransformer.
• Complete the 230kV Double Breaker Double Bus arrangement.
• Complete the 115kV Double Breaker Double Bus arrangement.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1038 of 1105
3 COMPLETED PROJECTS
Project Name Project Scope Targeted Date of Operation
Sandcreek-Bronx-Cabinet Rebuild Reconductor Bronx to Sand Creek with 795 ACSS Completed in 2017
Noxon Rapids 230kV Breaker
Replacement
Replace 6 limiting circuit breakers with 40kA fault current interrupting capability and operate at a steady state voltage of 253 kV Completed in 2018
Westside Transformer Replacement Auto#1 was replaced and placed into service Completed in 2018
Addy – Devil’s Gap 115kV
Transmission Line
Reconductor 5.19 miles (rebuild between Ford and Long Lake Tap) of limiting conductor which consist
of 266.8 ACSR and 397.5 ACSR conductor
resulting in a capacity limitation of 71.5 MVA at 40°C, to be rebuilt to a capacity of 150 MVA at 40°C (likely 240MVA)
Completed in Jan.
2019
(Data included in 2019 Master Case)
Saddle Mountain Integration Othello SS – Warden No.1 115kV Transmission Line upgraded to minimum 240 MVA @ 40°C.
Completed in Feb. 2019 (Data included in
2019 Master Case)
Othello – Warden#2 Partial
Rebuild (Saddle Mountain)
** included in 2020 studies
Replace 2.8 Miles of conductor w/ 795 ACSS
200°C from OSS to OTH City.
Completed in March 2019
(Data included in 2019 Master Case)
Lee & Reynolds Rebuild Substation rebuild. Install 2 – 30 MVA transformers
and 6 feeders
Completed in May
2019
Hallett & White Rebuild Substation rebuild. Install 2 – 30 MVA transformers
and 6 feeders
Completed in June
2019
North Lewiston Reactors Install two 50 MVAr shunt reactors to the existing 230kV bus at North Lewiston Station
Completed in July
2019 (Data included in 2019 Master Case)
Ford Substation Rebuild Rebuild station with 10 MVA transformer. Tapped off of ADD-DGP line Completed in December 2019
Boulder Substation Install 1 – 30 MVA transformer for load support Completed in October 2019
Priest River Feeder bay rebuild, expanded to two feeders Completed in October 2018
TABLE 2 COMPLETED PROJECTS

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1039 of 1105
V TECHNICAL ANALYSIS RESULTS
1 STEADY STATE CONTINGENCY ANALYSIS
The state of the current system study examined system normal and outage simulations on all
seasons of the 2020 base cases to determine the present ‘state of the system’ as it exists
today. The existing system configuration was modeled in 2020 Heavy and Light Summer,
2020-21 Heavy and Light Winter, 2020 Spring (high generation, low load) and 2020 high east to west transfer (Montana-Northwest Path 8 and West of Hatwai Path 6 near limits).
Included in the 2020 cases were completed projects and select projects under construction.
Significant system reinforcements or system changes since 2018 are as follows:
• Ninth and Central distribution load moved onto the 115kV bus.
• Westside 230/115 auto-transformers increased to 250 MVA.
• Coeur d’Alene – Pine Creek 115kV line increased capacity to 240 MVA.
• Adams-Neilson Solar (20 MVA) interconnected at Lind Substation.
• Cabinet – Bronx – Sand Creek 115kV line increased capacity to 143 MVA.
• Addy – Devils Gap 115kV line increased capacity to 120 MVA.
• Lind – Warden 115kV line increased capacity to 262 MVA.
• Othello SS – Warden #1 115kV line increased capacity to 262 MVA.
• Othello SS – Warden #2 115kV line increased capacity to 123 MVA.
• North Lewiston Reactors – two steps of 50 MVAr each.
• Benton – Othello SS 115kV line increased capacity to 138 MVA
Known outages of generation or transmission facilities with a duration of at least six months
were also included in the 2020 cases as follows:
• Lancaster – Noxon 230kV line derated to 255 MVA by BPA beginning in 2017.
Study results show several previously known issues are now resolved, and few new problems
have been observed in the current studies. None of the contingencies evaluated resulted in
Instability, Cascading, Uncontrolled Separation or IROLs. Study results are summarized as follows.
1.1 Thermal Issues
P0 – No system elements show thermal overload under system normal conditions.
P1.1-P1.4 – No system elements show thermal overload under N-1 conditions, such as the loss of a generator, transmission circuit, transformer or shunt device.
P2.1 – No system elements show thermal overload with the opening of a line section without a
fault during peak loading.
• Loss of the Liberty Lake – Otis Orchards 115kV line section during summer loading may
load the Ninth & Central – Opportunity 115kV line (up to 98%).
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1040 of 1105
• Loss of the Nelson – Ninth & Central 115kV line section during summer loading may
load the Opportunity – Otis Orchards 115kV line (up to 98%).
• Planned mitigation is to complete the Spokane Valley Transmission Reinforcement (fall
of 2021).
P2.2 – Several system elements can become thermally overloaded resulting from a bus section fault during peak loading.
• Loss of the Lolo 115kV bus during summer loading may overload the Clearwater – North Lewiston 115kV line (up to 96%, 116% if either Clearwater generator is offline)
o The Clearwater – North Lewiston 115kV line is protected by thermal relays and
will automatically drop load (157MW of load, 48MW of generation) when
overloaded per SOP 03.
• Loss of the Hot Springs 230kV bus during high Montana to Northwest (Path 8) transfers
may overload the Lancaster – Rathdrum 230kV line (up to 107%).
o Known issue with BPA’s Lancaster – Rathdrum 230kV line derate. BPA will mitigate in real time until the line derate is corrected (fall of 2021).
• Loss of the Rathdrum 115kV east bus during summer loading may overload the Rathdrum 230/115 transformer #1 (up to 103%) and overload the Ramsey – Rathdrum #1 115kV line (up to 109%).
o Existing mitigation is transfer Coeur d’Alene area load to Pine Creek.
o Refer to Coeur d'Alene System Reinforcement.
• Loss of the Westside 115kV southwest bus during summer loading may overload the
Ross Park – Third & Hatch 115kV line (up to 114%), the Francis & Cedar – Northwest 115kV line (up to 105%), and the Post Street – Third & Hatch 115kV line (up to 111%).
o Existing mitigation is to shed load (up to 60MW) in the South Spokane area until
Westside rebuild is complete.
o Planned mitigation is to complete the Westside Station Rebuild (fall of 2022).
• Loss of the Larson 115kV bus during spring and summer loading may overload the
Chelan - Stratford 115kV line (up to 112%).
o Existing mitigation is to move open point on the Devils Gap – Stratford 115kV line
to Devils Gap.
P2.3 – Several system elements can become thermally overloaded resulting from an internal breaker fault (non-bus tie breaker) during peak loading:
• A breaker failure on the Lolo 115kV bus (5 CB’s & 1 CS) during summer loading may overload the Clearwater – North Lewiston 115kV line (up to 96%, 116% if either Clearwater generator is offline).
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1041 of 1105
o The Clearwater – North Lewiston 115kV line is protected by thermal relays and
will automatically drop load (157MW of load, 48MW of generation) when
overloaded per SOP 03.
• A breaker failure on the Hot Springs 230kV bus (6 CB’s) during high east to west
transfers may overload the Lancaster – Rathdrum 230kV line (up to 106%).
o Known issue with BPA’s Lancaster – Rathdrum 230kV line derate. BPA will mitigate in real time until derate is corrected (fall of 2021).
• A breaker failure on the Rathdrum 115kV east bus (7 CB’s) during summer loading may
overload the Ramsey – Rathdrum #1 115kV line (up to 101%) and load the Rathdrum 230/115 transformer #1 to near rating.
o Existing mitigation is transfer Coeur d’Alene area load to Pine Creek.
o Refer to Coeur d'Alene System Reinforcement.
• A breaker failure on the Westside 115kV southwest bus (3 CB’s) during summer loading
may overload the Ross Park – Third & Hatch 115kV line (up to 114%), the Francis &
Cedar – Northwest 115kV line (up to 105%), and the Post Street – Third & Hatch 115kV line (up to 111%).
o Existing mitigation is to shed load (up to 60MW) in the South Spokane area.
o Planned mitigation is to complete the Westside Station Rebuild (fall of 2022).
• A breaker failure on the Larson 115kV bus (9 CB’s) during spring and summer loading
may overload the Chelan - Stratford 115kV line (up to 112%).
o Existing mitigation is to move open point on the Devils Gap – Stratford 115kV line
to Devils Gap.
P2.4 – Several system elements can become thermally overloaded resulting from an internal breaker fault on a bus tie breaker during peak loading:
• A Beacon 230kV bus tie breaker failure during summer loading may overload the Bell
230/115 transformer #6 (up to 100%), the Bell – Northeast 115kV line (up to 114%), and the Francis & Cedar – Northwest 115kV line (up to 105%).
o Existing mitigation is to shed load (up to 40MW) in the North Spokane area.
o Refer to South Spokane Transmission Reinforcement.
• A Beacon 115kV bus tie breaker failure during summer loading may overload the
Opportunity – Otis Orchards 115kV line (up to 122%), the Francis & Cedar – Northwest
115kV line (up to 121%), the Northwest – Westside 115kV line (up to 116%), and the College & Walnut – Westside 115kV line (up to 102%).
o Existing mitigation is to shed load (up to 90MW) in the South Spokane area.
o Refer to South Spokane Transmission Reinforcement.
• A Boulder 115kV bus tie breaker failure during summer loading may overload the Ninth
& Central – Opportunity 115kV line (up to 147%).
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1042 of 1105
o Existing mitigation is to shed load (up to 56MW) east of Otis Orchards.
o Planned mitigation is to complete the Spokane Valley Transmission Reinforcement (fall of 2021).
• A Ninth & Central 115kV bus tie breaker failure during summer loading may overload
the Ross Park – Third & Hatch 115kV line (up to 95%, 100% with W2E offline).
o Existing mitigation is to shed load (up to 10MW) in the South Spokane area.
o Refer to South Spokane Transmission Reinforcement.
P3 – Several system elements can become thermally overloaded resulting from the loss of a
generator; followed by system adjustments; followed by a subsequent loss of an additional
transmission circuit, transformer or shunt device.
• Loss of Clearwater unit #3 or #4 followed by the loss of either Clearwater 115/34
transformer during any seasonal loading may overload the remaining Clearwater 115/34
transformer (up to 113%).
o Existing mitigation is to reduce facility load.
• Loss of Clearwater generator unit #3 or #4 followed by the loss of Hatwai – Lolo 230kV
line during summer loading may overload the Clearwater – North Lewiston 115kV line
(up to 107%).
o The Clearwater – North Lewiston 115kV line is protected by thermal relays and
will automatically drop load when overloaded per SOP 03.
P4 and P5 – No further results beyond those identified in P2.2 thru P2.4
P6 – Several system elements can become thermally overloaded resulting from an N-1-1
contingency event. This is described as the loss of a transmission circuit, transformer or shunt
device; followed by system adjustments; followed by a subsequent loss of an additional
transmission circuit, transformer or shunt device.
• Loss of the Addy – Bell 115kV line, followed by load restoration (Addy to Loon Lake
115kV line section outage shows worst performance), followed by:
o The loss of either Beacon 230/115 transformer during summer loading may overload the Bell 230/115 transformer #6 (up to 105%).
▪ Existing mitigation is for BPA to operate within their short term rating.
o The loss of Bell 230/115 transformer #6 during summer loading may overload the Beacon – Bell 115kV line (up to 113%) and Beacon – Northeast 115kV line (up to
102%).
▪ Existing mitigation is to transfer Waikiki to Beacon - Francis & Cedar 115kV line.
▪ Refer to North Spokane Transmission Reinforcement.
• Loss of the Airway Heights – Devils Gap 115kV line, followed by load restoration (Devils
Gap – West Plains 115kV line section outage shows worst performance), followed by:
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1043 of 1105
o The loss of Nine Mile – Westside 115kV line during light spring loading may
overload the Addy – Devils Gap 115kV line (up to 107%).
▪ Existing mitigation is to limit generation at Nine Mile to 8MW per SOP 20
▪ Planned mitigation is to complete the Addy – Devils Gap 115kV line
section rebuild by correcting bottleneck at Devils Gap (spring of 2020).
• Loss of the either Beacon 230/115 transformer followed by:
o The loss of the remaining Beacon 230/115 transformer during summer loading
may overload the Bell 230/115 transformer #6 (up to 126%), the Beacon – Northeast 115kV line (up to 104%), and the Francis & Cedar – Northwest 115kV line (up to 100%).
▪ Existing mitigation is for BPA to operate within their short term rating and
for Avista to shed load (up to 33MW) at Waikiki or bring up Northeast CT
▪ Refer to West Plains System Reinforcement and South Spokane
Transmission Reinforcement.
o The loss of Bell 230/115 transformer #6 during summer loading may overload the remaining Beacon 230/115 transformer (up to 119%).
▪ Existing mitigation is for BPA and Avista to shed load (up to 80MW) in the
north Spokane area
▪ Refer to West Plains System Reinforcement and South Spokane Transmission Reinforcement.
• Loss of the either Beacon – Bell 230kV line followed by:
o The loss of the remaining Beacon - Bell 230kV line during summer loading may
overload the Bell 230/115 transformer #6 (up to 118%).
▪ Existing mitigation is for BPA to operate within their short term rating.
• Loss of the Beacon – Bell 115kV line, followed by:
o The loss of Bell 230/115 transformer #6 during summer loading may overload the Beacon – Northeast 115kV line (up to 126%) and the Bell – Northeast 115kV line
(up to 102%).
▪ Existing mitigation is to transfer Waikiki to Francis & Cedar.
▪ Refer to North Spokane System Reinforcement.
• Loss of the either Beacon – Ninth & Central 115kV line followed by:
o The loss of the remaining Ninth & Central 115kV line during summer loading may
overload the Ross Park – Third & Hatch 115kV line (up to 123%).
▪ Existing mitigation is to shed load (up to 70MW) in the South Spokane
area.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1044 of 1105
▪ Refer to West Plains System Reinforcement and South Spokane
Transmission Reinforcement.
o The loss of the Beacon – Ross Park 115kV line during summer loading may overload the remaining Beacon – Francis & Cedar 115kV line (up to 106%).
▪ Existing mitigation is to open Ninth & Central – Opportunity 115kV line at
Ninth & Central
▪ Refer to West Plains System Reinforcement and South Spokane Transmission Reinforcement.
o The loss of the Ross Park – Third & Hatch 115kV line during summer loading
may overload the remaining Beacon – Francis & Cedar 115kV line (up to 102%).
▪ Existing mitigation is to open Ninth & Central – Opportunity 115kV line at
Ninth & Central
▪ Refer to West Plains System Reinforcement and South Spokane Transmission Reinforcement.
• Loss of the Beacon – Northeast 115kV line, followed by:
o The loss of Bell 230/115 transformer #6 during summer loading may overload the
Beacon – Bell 115kV line (up to 162%).
▪ BPA has to radialize their load at Bell pre-contingency
▪ Refer to North Spokane System Reinforcement.
• Loss of the Beacon – Ross Park 115kV line followed by:
o The loss of the either Beacon – Ninth & Central 115kV line during summer
loading may overload the remaining Beacon – Ninth & Central 115kV line (up to
107%).
▪ Existing mitigation is to open Ninth & Central – Opportunity 115kV line at
Ninth & Central.
▪ Planned mitigation is to complete the Spokane Valley Transmission Reinforcement (fall of 2021).
• Loss of the Bell 230/115 transformer #6 followed by:
o The loss of the either Beacon 230/115 transformer during summer loading may
overload the remaining Beacon 230/115 transformer (up to 118%).
▪ Existing mitigation is to shed load (up to 80MW) in the north Spokane area
▪ Refer to West Plains System Reinforcement and South Spokane
Transmission Reinforcement.
o The loss of the Beacon – Northeast 115kV line during summer loading may overload the Beacon – Bell 115kV line (up to 162%).
▪ BPA and Avista shed load (up to 80MW) in the north Spokane area.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1045 of 1105
▪ Refer to North Spokane System Reinforcement.
o The loss of the Beacon – Bell 115kV line during summer loading may overload the Beacon – Northeast 115kV line (up to 126%).
▪ Planning mitigation is to transfer Waikiki to Francis & Cedar.
▪ Refer to North Spokane System Reinforcement.
• Loss of the Bell – Northeast 115kV line, followed by load restoration (Waikiki will auto-
transfer to the Beacon – Francis & Cedar 115kV line), followed by:
o The loss of Bell 230/115 transformer #6 during summer loading may overload the
Beacon – Bell 115kV line (up to 105%).
▪ BPA has to radialize their load at Bell pre-contingency
▪ Refer to North Spokane System Reinforcement.
• Loss of the Bell – Westside 230kV line followed by:
o The loss of either Beacon 230/115 transformer during summer loading may
overload the Bell 230/115 transformer #6 (up to 107%) and the remaining
Beacon 230/115 transformer (up to 106%).
▪ Existing mitigation is for BPA to operate within their short term rating on
Bell 230/115 transformer #6 and for Avista to shed load (up to 50MW) at
Waikiki.
▪ Refer to West Plains System Reinforcement and South Spokane Transmission Reinforcement.
• Loss of the Benewah – Boulder 230kV line followed by:
o Loss of the Dworshak – Hatwai 500 during high east to west transfers may
overload the Benewah – Pine Creek 230kV line (up to 126%).
▪ Existing mitigation is to limit WMH to 1450MW and reduce Avista’s share of MT-NW by 200MW per SOP 28.
• Loss of the Benewah – Pine Creek 230kV line followed by:
o Loss of the Cabinet – Rathdrum 230 line during high east to west transfers may
overload the Lancaster - Noxon 230kV line (up to 134%).
▪ Existing mitigation is to limit WMH to 1350MW and reduce Avista’s share of MT-NW by 200MW per SOP 28.
• Loss of the Benton – Othello SS 115kV line, followed by load restoration (Benton to
South Othello 115kV line section outage shows worst performance), followed by:
o The loss of the Sand Dunes – Warden 115kV line during summer loading may
overload the Larson – Sand Dunes – Warden 115kV line (up to 116%).
▪ Existing mitigation is to open the Larson – Sand Dunes – Warden 115kV line at Warden per SOP 21.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1046 of 1105
▪ Planned mitigation is to complete the Saddle Mountain project Phase I
and II (fall of 2022).
• Loss of the Cabinet - Noxon 230kV line followed by:
o Loss of the Noxon – Pine Creek 230kV line during high WMH and east to west
transfers may overload the Lancaster - Noxon 230kV line (up to 145%).
▪ Existing mitigation is to arm RAS, limit Cabinet Gorge to 200MW, limit
WMH to 1200MW and reduce Avista’s share of MT-NW by 200MW per
SOP 28.
• Loss of the College & Walnut – Westside 115kV line, followed by load restoration (Fort
Wright – Westside 115kV line section outage shows worst performance), followed by:
o The loss of the Ninth & Central – Third & Hatch 115kV line during summer loading may overload the Ross Park – Third & Hatch 115kV line (up to 105%).
▪ Existing mitigation is to shed load (up to 10MW) at Fort Wright.
▪ Refer to West Plains System Reinforcement and South Spokane Transmission Reinforcement.
o The loss of the either Beacon – Ninth & Central 115kV line during summer
loading may overload the remaining Beacon – Ninth & Central 115kV line (up to
101%).
▪ Existing mitigation is to open Ninth & Central – Opportunity 115kV line at
Ninth & Central
▪ Planned mitigation is to complete the Spokane Valley Transmission Reinforcement (fall of 2021).
• Loss of the Devils Gap - Stratford 115kV line, followed by load restoration (Stratford –
Wilson Creek 115kV line section outage shows worst performance), followed by:
o The loss of the Larson - Stratford 115kV line during summer loading may
overload the Chelan - Stratford 115kV line (up to 107%).
▪ Existing mitigation is to open the Chelan - Stratford 115kV line at Stratford per SOP 21.
• Loss of the Dry Creek – North Lewiston 230kV line followed by:
o Loss of the Hatwai - Lolo 230kV line during summer loading and high ID-NW transfers may overload the Clearwater – North Lewiston 115kV line (up to 167%),
Dry Creek – North Lewiston 115kV line (up to 121%), and North Lewiston
230/115 transformer #1 (up to 138%).
▪ Existing mitigation is to arm Lolo-Oxbow Back Trip, open Lolo – Pound Lane 115kV line at Lolo, open Lolo – Nez Perce 115kV line at Nez Perce, Open Dry Creek – North Lewiston 115kV line at North Lewiston, and open
Dry Gulch 69 kV tie.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1047 of 1105
▪ Refer to Lewiston/Clarkston System Reinforcement.
• Loss of the Francis & Cedar – Ross Park 115kV line, followed by load restoration (Lions & Standard – Ross Park 115kV line section outage shows worst performance), followed by:
o The loss of the Northwest - Westside 115kV line during summer loading may
overload the Beacon – Francis & Cedar 115kV line (up to 109%).
▪ Existing mitigation is to open the Beacon – Francis & Cedar 115kV line at
Francis & Cedar.
▪ Refer to North Spokane System Reinforcement.
• Loss of the Larson – Stratford 115kV line, followed by:
o The loss of the Devils Gap - Stratford 115kV line during spring and summer
loading may overload the Chelan - Stratford 115kV line (up to 107%).
▪ Existing mitigation is to limit generation at Main Canal and Summer Falls to a total of 90MW per SOP 21.
• Loss of the Larson – Sand Dunes – Warden 115kV line, followed by load restoration
(Wheeler to Basset Junction 115kV line section outage shows worst performance),
followed by:
o The loss of the Sand Dunes – Warden 115kV line during spring and summer
loading will overload the Benton – Othello SS 115kV line and result in voltage
collapse in the Othello area (drops up to 168MW).
▪ Existing mitigation is to open the Benton – Othello SS 115kV line at Othello SS per SOP 21.
▪ Planned mitigation is to complete the Saddle Mountain project Phase I
and II (fall of 2022). This still results in low voltage on GCPD’s system.
• Loss of the Hatwai – Lolo 230kV line followed by:
o Loss of the Dry Creek – Lolo 230kV line during summer loading and high ID-NW transfers may overload the Clearwater – North Lewiston 115kV line (up to 197%) and Dry Creek – Pound Lane 115kV line (up to 119%) or the;
o Loss of the Dry Creek – North Lewiston 230kV line during summer loading and
high ID-NW transfers may overload the Clearwater – North Lewiston 115kV line (up to 167%), Dry Creek – North Lewiston 115kV line (up to 121%), and North Lewiston 230/115 transformer #1 (up to 138%) or the;
o Loss of the North Lewiston 230/115 transformer during summer loading and high
ID-NW transfers may overload the Dry Creek – North Lewiston 230kV line (up to
116%).
▪ Arm Lolo-Oxbow Back Trip, open Lolo – Pound Lane 115kV line at Lolo,
open Lolo – Nez Perce 115kV line at Nez Perce, Open Dry Creek – North
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1048 of 1105
Lewiston 115kV line at North Lewiston, and open Dry Gulch 69 kV tie per
SOP 33.
• This leaves Clearwater – North Lewiston 115kV line in service, but ready to trip via thermal relays for a subsequent outage.
▪ Refer to Lewiston/Clarkston System Reinforcement.
• Loss of the Moscow 230/115 transformer followed by:
o The loss of the Shawnee 230/115 transformer during any season will overload the Moscow – Orofino 115kV line and result in voltage collapse in the Moscow/Pullman area (drops up to 186MW).
▪ Existing mitigation is to open the Moscow – Orofino 115kV line at Moscow.
No current System Operating Procedure.
▪ Can only recover load in the Moscow area (from Orofino & North
Lewiston), which leaves up to 70MW offline until autotransformer issue is
corrected,
▪ Refer to Palouse System Reinforcement.
• Loss of the Moscow – South Pullman 115kV line, followed by load restoration (Moscow
– North Moscow 115kV line section outage shows worst performance), followed by:
o The loss of the Shawnee 230/115 transformer during summer loading may
overload the Moscow – Terre View 115kV line (up to 110%).
▪ Existing mitigation is to transfer Moscow City load to North Lewiston.
▪ Refer to Palouse System Reinforcement.
• Loss of the Moscow – Terre View 115kV line, followed by load restoration (Moscow – North Moscow 115kV line section outage shows worst performance), followed by:
o The loss of the Shawnee 230/115 transformer during summer loading may
overload the Moscow – South Pullman 115kV line (up to 107%).
▪ Existing mitigation is to transfer Moscow City load to North Lewiston.
▪ Refer to Palouse System Reinforcement.
• Loss of the North Lewiston 230/115 transformer followed by:
o Loss of the Hatwai - Lolo 230kV line during summer loading and high ID-NW transfers may overload the Dry Creek – North Lewiston 115kV line (up to 98%),
▪ Arm Lolo-Oxbow Back Trip per SOP 33.
▪ Refer to Lewiston/Clarkston System Reinforcement.
• Loss of the Nine Mile – Westside 115kV line, followed by load restoration (Indian Trail – Westside 115kV line section outage shows worst performance), followed by:
o The loss of Airway Heights – Devils Gap 115kV line during light spring loading
may overload the Addy – Devils Gap 115kV line (up to 107%).
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1049 of 1105
▪ Existing mitigation is to limit generation at Nine Mile to 8MW per SOP 20
▪ Planned mitigation is to complete the Addy – Devils Gap 115kV line section rebuild by correcting bottleneck at Devils Gap (spring of 2020).
• Loss of the Ninth & Central – Sunset 115kV line, followed by load restoration (Glenrose
– Ninth & Central 115kV line section outage shows worst performance), followed by:
o The loss of the Beacon – Ross Park 115kV line during summer loading may
overload the Ninth & Central – Third & Hatch 115kV line (up to 91%, 95% with
W2E offline, increases to 100% after Irvin is complete).
▪ Refer to West Plains System Reinforcement and South Spokane Transmission Reinforcement.
o The loss of the Metro – Post Street 115kV line during summer loading may
overload the Sunset – Westside 115kV line (up to 106%, 105% with W2E offline,
increases to 109% after Irvin is complete).
▪ Planned mitigation is to complete the Metro Substation rebuild and
associated projects (spring of 2024).
o The loss of the Metro – Sunset 115kV line during summer loading may overload the Sunset - Westside 115kV line (up to 96%, 96% with W2E offline, increases to 99% after Irvin is complete).
▪ Refer to West Plains System Reinforcement.
o The loss of the Ninth & Central – Third & Hatch 115kV line during summer
loading may overload the Ross Park – Third & Hatch 115kV line (up to 98%, 103% with W2E offline, increases to 108% after Irvin is complete).
▪ Refer to West Plains System Reinforcement.
• Loss of the Noxon – Pine Creek 230kV line followed by:
o Loss of the Cabinet - Rathdrum 230kV line during high WMH and east to west
transfers may overload the Lancaster - Noxon 230kV line (up to 121%).
▪ Existing mitigation is to arm RAS, limit WMH to 1350MW and reduce
Avista’s share of MT-NW by 200MW per SOP 28.
• Loss of the Opportunity – Otis Orchards 115kV line, followed by load restoration (Liberty
Lake – Otis Orchards line section outage shows worst performance), followed by:
o The loss of the either Beacon 230/115 transformer during summer loading may
overload the remaining Beacon 230/115 transformer (up to 98%).
▪ Refer to West Plains System Reinforcement and South Spokane Transmission Reinforcement.
o The loss of the either Ninth & Central 115kV line during summer loading may
overload the remaining Ninth & Central 115kV line (up to 108%).
▪ Existing mitigation is to shed load (up to 20MW) in the South Spokane area.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1050 of 1105
▪ Planned mitigation is to complete the Spokane Valley Transmission
Reinforcement (fall of 2021).
• Loss of the Othello SS – Warden #2 115kV line, followed by load restoration (Lee & Reynolds - Warden 115kV line section outage shows worst performance), followed by:
o The loss of the Othello SS – Warden #1 115kV line during spring and summer
loading may overload the Benton – Othello SS 115kV line (up to 125%).
▪ Existing mitigation is to open the Benton – Othello SS 115kV line at
Othello SS per SOP 21.
▪ Planned mitigation is to complete the Benton – Othello SS project (spring of 2020).
• Loss of the Pine Street – Rathdrum 115kV line, followed by load restoration (Old Town
– Pine Street 115kV line section outage shows worst performance), followed by:
o The loss of the Rathdrum 230/115 transformer #2 during summer loading may
overload the remaining Rathdrum 230/115 transformer #1 (up to 117%, 96% with
CDA-PIN 115 closed).
▪ Existing mitigation is to operate Coeur d’Alene – Pine Creek 115kV closed through per SOP 36.
▪ Refer to Coeur d'Alene System Reinforcement.
• Loss of either Rathdrum 230/115 transformer followed by:
o The loss of the remaining Rathdrum 230/115 transformer during any season will overload the Pine Street – Rathdrum 115kV line and result in voltage collapse in the Coeur d’Alene area (drops up to 275MW).
▪ Existing mitigation is to open the Pine Street – Rathdrum 115kV line at
Rathdrum per SOP 36. Note that closing though on the Coeur d’Alene –
Pine Creek 115kV does not mitigate for the loss of both Rathdrum 230/115 transformers, due to Pine Street – Rathdrum 115kV line overload (up to 127%).
▪ Refer to Coeur d'Alene System Reinforcement.
• Loss of the Sand Dunes – Warden 115kV line, followed by:
o The loss of the Larson – Sand Dunes – Warden 115kV line 115kV line during
summer loading may overload the Benton – Othello SS 115kV line (up to 212%).
▪ Existing mitigation is to open the Larson – Sand Dunes – Warden 115kV
line at Warden per SOP 21.
▪ Planned mitigation is to complete the Benton – Othello SS project (spring of 2020).
• Loss of the Sunset – Westside 115kV line, followed by load restoration (Garden Springs
– Waste to Energy 115kV line section outage shows worst performance), followed by:
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1051 of 1105
o The loss of the Airway Heights – Devils Gap 115kV line during summer loading
may overload the College & Walnut – Westside 115kV line (up to 102%).
▪ Existing mitigation is to shed load (up to 10MW) at Fort Wright.
▪ Refer to West Plains System Reinforcement.
o The loss of the College & Walnut – Westside 115kV line during summer loading may overload the Francis & Cedar – Northwest 115kV line (up to 102%), the Post Street – Third & Hatch 115kV line (up to 103%), and the Ross Park – Third & Hatch 115kV line (up to 110%).
▪ Existing mitigation is to shed load (up to 50MW) in the South Spokane
area.
▪ Refer to West Plains System Reinforcement and South Spokane
Transmission Reinforcement.
o The loss of the Francis & Cedar – Northwest 115kV line during summer loading may overload the College & Walnut – Westside 115kV line (up to 111%).
▪ Existing mitigation is to shed load (up to 40MW) in the South Spokane
area.
▪ Refer to West Plains System Reinforcement and South Spokane Transmission Reinforcement.
o The loss of the Metro – Post Street 115kV line during summer loading may
overload the Ninth & Central – Sunset 115kV line (up to 114%).
▪ Existing mitigation is to shed load (up to 20MW) in the South Spokane
area.
▪ Planned mitigation is to complete the Metro Substation rebuild and associated projects (spring of 2024).
o The loss of the Metro – Sunset 115kV line during summer loading may overload
the Ninth & Central – Sunset 115kV line (up to 102%).
▪ Existing mitigation is to shed load (up to 10MW) in the South Spokane area.
▪ Planned mitigation is to complete the Ninth & Central – Sunset 115kV line
rebuild (Southeast Substation bottleneck) (spring of 2020).
o The loss of the Northwest – Westside 115kV line during summer loading may
overload the College & Walnut – Westside 115kV line (up to 119%).
▪ Existing mitigation is to shed load (up to 80MW) in the South Spokane area.
▪ Refer to West Plains System Reinforcement and South Spokane
Transmission Reinforcement.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1052 of 1105
o The loss of the Post Street – Third & Hatch 115kV line during summer loading
may overload the College & Walnut – Westside 115kV line (up to 109%).
▪ Existing mitigation is to shed load (up to 30MW) in the South Spokane area.
▪ Refer to West Plains System Reinforcement.
o The loss of the Ross Park – Third & Hatch 115kV line during summer loading may overload the College & Walnut – Westside 115kV line (up to 103%).
▪ Existing mitigation is to shed load (up to 10MW) at Fort Wright.
▪ Refer to West Plains System Reinforcement and South Spokane Transmission Reinforcement.
• Loss of the Sunset – Westside 115kV line, followed by gen/load restoration (Waste to Energy – Westside 115kV line section outage shows worst performance), followed by:
o The loss of the College & Walnut – Westside 115kV line during summer loading
may overload the Ross Park – Third & Hatch 115kV line (up to 104%).
▪ Existing mitigation is to shed load (up to 20MW) in the South Spokane
area.
▪ Refer to West Plains System Reinforcement and South Spokane Transmission Reinforcement.
o The loss of the Francis & Cedar – Northwest 115kV line during summer loading
may overload the College & Walnut – Westside 115kV line (up to 104%).
▪ Existing mitigation is to shed load (up to 20MW) in the South Spokane area.
▪ Refer to West Plains System Reinforcement and South Spokane
Transmission Reinforcement.
o The loss of the Metro – Post Street 115kV line during summer loading may
overload the Ninth & Central – Sunset 115kV line (up to 102%).
▪ Existing mitigation is to shed load (up to 10MW) in the South Spokane
area.
▪ Planned mitigation is to complete the Ninth & Central – Sunset 115kV line
rebuild (Southeast Substation bottleneck) (spring of 2020).
o The loss of the Northwest – Westside 115kV line during summer loading may overload the College & Walnut – Westside 115kV line (up to 112%).
▪ Existing mitigation is to shed load (up to 50MW) in the South Spokane
area.
▪ Refer to West Plains System Reinforcement and South Spokane Transmission Reinforcement.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1053 of 1105
o The loss of the Post Street – Third & Hatch 115kV line during summer loading
may overload the College & Walnut – Westside 115kV line (up to 102%).
▪ Existing mitigation is to shed load (up to 10MW) in the South Spokane area.
▪ Refer to West Plains System Reinforcement.
o The loss of the Ross Park – Third & Hatch 115kV line during summer loading may overload the College & Walnut – Westside 115kV line (up to 97%).
P7 – No system elements show thermal overload resulting from an N-2 contingency event.
This is described as the loss of any two adjacent circuits on common structure (vertical or
horizontal) and excludes circuits of (1) mile.
1.2 Voltage Issues
P0 – No voltage issues were identified under system normal conditions.
• Minor high voltage is observed under system normal and off-peak loading conditions in the Big Bend area.
o Issue remains under observation.
• Minor low voltage has been observed under system normal conditions in PacifiCorp’s
69 kV system.
o PacifiCorp planned mitigation is to upgrade the Dry Gulch 115/69 kV transformer from 20 MVA to a 50 MVA transformer with voltage regulation (LTC).
P1.1-P1.4 – No voltage issues were identified under N-1 conditions, such as the loss of a
generator, transmission circuit, transformer or shunt device.
P2.1 – Several voltage issues were identified with the opening of a line section w/o a fault during peak loading:
• Loss of the Roxboro – Warden 115kV line section requires transferring area load to Devils Gap and/or Shawnee, may result in low voltage at Roxboro (0.93pu).
o Existing mitigation is to shed load at Roxboro (up to 20MW) per SOP 21.
• Loss of the Stratford – Wilson Creek 115kV line section requires transferring area load
to Devils Gap, which may result in a high voltage step change (0.06pu) when inserting
each 13.4 MVAr step at Othello.
o Step change in voltage results in up to 40MW of irrigation load loss.
o Planned mitigation is to investigate reducing cap bank step size.
• Loss of the Garden Springs – Hayford 115kV line section requires transferring area load
to Airway Heights, which may result in low voltage at Cheney (0.95pu).
o Existing mitigation is to transfer Cheney and Four Lakes to the Sunset – Shawnee 115kV line per SOP 12.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1054 of 1105
P2.2 – Several voltage issues were identified resulting from a bus section fault during peak
loading:
• Loss of the Sand Dunes 115kV bus during summer loading may result in low voltage at Ritzville (0.95pu) and Othello City (0.95pu).
o Existing mitigation is to transfer load at Ritzville to Devils Gap
P2.4 – Several voltage issues were identified resulting from an internal breaker fault on a bus
tie breaker during peak loading:
• A Boulder 115kV bus tie breaker failure during summer loading may result in voltage collapse in the Spokane Valley.
o Shed load east of Otis Orchards
P3 – No further results beyond those identified in P1 and P2.1
P4 & P5 – No further results beyond those identified in P2.2 thru P2.4
P6 – No voltage issues were identified resulting from an N-1-1 contingency event that were not
captured in the previous thermal results section. This is described as the loss of a transmission
circuit, transformer or shunt device; followed by system adjustments; followed by a subsequent
loss of an additional transmission circuit, transformer or shunt device.
P7 – No voltage issues were identified resulting from an N-2 contingency event. This is described as the loss of any two adjacent circuits on common structure (vertical or horizontal) and excludes circuits of (1) mile.
1.3 Radial and Consequential Load Loss Issues
The present steady state contingency analysis methods allows for observation of
consequential load loss for each studied contingency. Improved study methods are desired to
capture both the amount of consequential load loss and the inability to restore service to customers. The following list identifies transmission system contingencies resulting in undesired consequential load loss. The list is not comprehensive of all radial transmission system elements and will be improved in subsequent studies.
• P1.1 – Loss of the Addy - Gifford 115kV line during any season results in an outage to Gifford (9MW)
o Addy has a main/aux bus arrangement for substation related outages at Addy
• P1.1 – Loss of the Lind – Washtucna 115kV line during any season results in an outage
to Delight and Washtucna (total of 3MW)
o The Lind bypass switch provides service for substation related outages at Lind
• P1.1 – Loss of the Orofino – Weippe 115kV line during any season results in an outage
to Weippe (4MW)
o The Orofino bypass switch A196 provides service for substation related outages at Orofino
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1055 of 1105
• P1.3 – Loss of the Benewah 230/115 transformer #1 (drops 20MW load), followed by
load restoration (transfer Setters load to Ninth & Central and close the Benewah – Pine
Creek 115kV line) did not result in load loss after load was restored from alternate
sources.
• P1.3 – A trip of either Cabinet Gorge GSU A or B (P1.3) during any season will drop all
units at Cabinet Gorge (up to 260MW) and clears the Cabinet 230kV bus due to the lack
of a high side GSU breaker. This outage severs the (2) primary station service feeds at Cabinet Gorge Hydro, it open ends the Cabinet – Noxon 230kV line, the Cabinet – Rathdrum 230kV line and the Cabinet 230/115kV autotransformer, it results in a reduction in WMH to 1100MW and cuts MT-NW by 200MW.
o Refer to Cabinet Gorge GSU Isolation.
• P2.4 – A Rathdrum 115kV bus tie breaker failure during any season drops load in the Coeur d’Alene area (drops up to 275MW).
• P7 / P6 – A forced outage of Beacon – Rathdrum 230kV line and Lancaster – Rathdrum
230kV line (common structure), followed by:
o The loss of the Cabinet – Rathdrum 230kV line during any season will overload
the Pine Street – Rathdrum 115kV line and result in voltage collapse in the Coeur
d’Alene area (drops up to 275MW).
▪ Open the Pine Street – Rathdrum 115kV line at Rathdrum per SOP 36
▪ Refer to Coeur d'Alene System Reinforcement.
2 VOLTAGE STABILITY ANALYSIS
No QV or PV issues were identified during this assessment.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1056 of 1105
3 STABILITY CONTINGENCY ANALYSIS
The following transient stability issues were identified during this assessment.
3.1 Kettle Falls Generator Out of Step
The Kettle Falls generator can become unstable if a time delayed three phase fault occurs on
the Addy – Kettle Falls 115kV Transmission Line near Addy. Studies indicate that speeding up
the Zone 2 clearing (time delay of 9 cycles, 13 cycles total clearing) is not sufficient to correct
this out of step issue.
The stability issue was addressed with the installation of an out of step relay (78) at Kettle Falls. The transient stability results are shown below and indicate that the local system returns to a stable state once the generators are tripped offline.

FIGURE 3: KETTLE FALLS GENERATION OOS.
Implementing a high speed communication aided tripping scheme on the Addy – Kettle Falls
115kV Transmission Line to improve stability performance of the Kettle Falls generation is necessary.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1057 of 1105
3.2 Nine Mile Generators Out of Step
All Nine Mile Hydro generators can become unstable if a time delayed three phase fault occurs on the Nine Mile – Westside 115kV Transmission Line near Westside. Studies indicate that speeding up the Zone 2 clearing (time delay of 9 cycles, 13 cycles total clearing) is not
sufficient to correct this out of step issue.
Units #3 and #4 at Nine Mile Hydro have recently been rebuilt, resulting in up to 28MW of total facility generation. These units were commissioned with an out of step relay (78), but units #1 and #2 do not have this protection. The transient stability results are shown below and indicate that the local system returns to a stable state once units #1 and #2 are tripped offline.

FIGURE 4: NINE MILE GENERATION OOS.
This issue is corrected after the Nine Mile - Westside 115kV Transmission Line is moved to the new Westside Southeast 115kV bus and the planned communication aided tripping is integrated.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1058 of 1105
3.3 Coeur d’Alene Area Voltage Recovery
During moderate to heavy loading, the Coeur d’Alene area has slow voltage recovery for a fault on the double circuit Boulder – Rathdrum and Lancaster – Rathdrum 230kV transmission lines (P7 contingency). The slow voltage recovery does not meet the WR1.1.4 Part 2
performance criteria as shown in Figure 5. Previous technical studies did not demonstrate the
same performance. The implementation of stalled motor modeling in the composite load model
contributes to the slow voltage recovery. Further detailed analysis is necessary to determine
the accuracy of the simulation and potential modeling improvements. The implementation of
the Coeur d’Alene System Reinforcement Project will address the voltage dip performance by
improving the strength of the local transmission system.

FIGURE 5: P7 CONTINGENCY VOLTAGE RECOVERY IN COEUR D'ALENE AREA.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1059 of 1105
5 SPARE EQUIPMENT ANALYSIS
Avista’s 230/115kV transformer spare equipment strategy could result in the unavailability of
these units for one year or more due to replacement lead time. The impact of a single
transformer out of service and subsequent P0, P1 and P2 contingencies was studied by area.
5.1 Big Bend Area
Avista does not currently have any 230/115kV autotransformers, in service, in the Big Bend
area.
5.2 Coeur d’Alene Area Transformers
Outage of either Rathdrum 230/115kV transformer may result in area overloads and low voltage problems for Rathdrum 115kV bus outages or the other Rathdrum transformer outage.
The Coeur d’Alene System Reinforcement Project has been identified for this purpose and will mitigate the bus issues.
Upgrading the existing #1 transformer, previously identified by Asset Management, will provide overload mitigation for some contingencies.
Additional analysis is required for mitigation of the double transformer outage.
5.3 Lewiston/Clarkston Area Transformers
Area transformer outages may result in overloads on the Lolo 230/115kV transformers. Area
115kV bus outages may result in area low voltage.
The Lolo Transformer Replacement Project Committed and Planned for completion by 2023
will mitigate the transformer overload problem.
Area low voltage mitigation will require further study.
5.4 Palouse Area Transformers
Outage of either the Moscow or Shawnee 230/115kV transformer may result in area low voltage and 115kV line overloads; outage of both transformers increases the severity.
The Palouse Area Reinforcement Project has been identified for this purpose.
5.5 Spokane Area Transformers
Outage of either Beacon 230/115kV transformer combined with an outage of either of the
Boulder or Westside 230/115kV transformers may result in overload the Bell#6 230/115kV
transformer. Additional instances of the Bell#6 transformer overloading as well area transformer overloading may occur for Beacon 230 and 115kV bus outages.
Upgrading of the BPA Bell#6 230/115kV transformer will mitigate the overload issues.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1060 of 1105
The South Spokane System Reinforcement Project has been identified for this purpose.
Additional analysis for an area solution is still required.
Detail results are presented in Appendix D.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1061 of 1105
6 SHORT CIRCUIT ANALYSIS
Sunset Substation was previously identified as having available short circuit current above the
interrupting capability of at least one of the circuit breakers. No additional violations were
identified in this year’s assessment.
The Sunset Substation Rebuild Project is Committed and Planned for completion by 2023
which will mitigate this problem.
Detailed results are presented in Appendix E.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1062 of 1105
8 FEEDER CAPACITY ANALYSIS
Feeder Capacity analysis was done for feeders that have SCADA data available. Table 3 is a
list of the 20 heaviest loaded feeders from the three year period 2016-2018. The peak
represents the highest five minute average for the season- summer or winter. Seasonal Capacity is the SCADA Variable Limit for 0°C and 40°C ambient temperatures. Project planned indicates whether a project has been considered, planned, or under construction. It should be noted that peak values are taken without regard to system status.
Detailed results are presented in Appendix H.
Peak Feeder Loading (2016-2018)
Feeder
Name
Summer Peak
Load (Amps)
Winter Peak
Load (Amps)
Summer
Capacity Limit
(Amps)
Winter Capacity
Limit (Amps)
Max
Usage
Project
Planned
WAK12F4 504 316 512 668 99% Yes
ROS12F1 481 521 499 571 96%
HUE142 493 325 512 613 96% Yes
F&C12F2 468 318 512 668 91%
NRC352 84 103 113 113 91%
ODN731 284 297 312 456 91%
COB12F1 463 343 512 668 90% Yes
DAL132 462 262 512 668 90% Yes
SE12F3 368 596 512 668 89% Yes
ORI12F3 111 266 208 302 88%
KET12F2 258 264 293 430 88%
AIR12F2 427 435 485 668 88% Yes
C&W12F6 446 355 512 608 87%
DAL131 522 402 601 668 87% Yes
LOL1359 356 258 413 635 86%
SE12F2 516 502 601 668 86% Yes
MEA12F1 440 284 512 668 86% Yes
GLN12F2 440 398 512 668 86%
APW112 477 436 557 618 86%
F&C12F4 438 321 512 668 86%
TABLE 3 PEAK FEEDER LOADING (2016-2018)

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1063 of 1105
AVISTA GENERAL
INFORMATION
A.1 GENERATION RESOURCES
Avista has a diverse mix of generation with a majority of its generation being hydro power
based on various projects located on the Spokane River and Clark Fork River. Avista owns
eight hydroelectric generating plants as well as coal (partial ownership), natural gas, and
wood-waste combustion plants in five eastern Washington, northern Idaho, eastern Oregon, and eastern Montana locations. Avista also utilizes power supply purchase and sale arrangements of varying lengths to meet a portion of its load requirements. Table 4 through Table 6 summarize the operational capacities of Avista generating projects.
TABLE 4: AVISTA HYDROELECTRIC GENERATION RESOURCES.
Project Name Fuel Location Area Project Start Date
Maximum Capability (MW)F
Monroe Street Spokane River Spokane, WA Spokane 1890 15.0
Post Falls Spokane River Post Falls, ID CdA 1906 18.0 Nine Mile Spokane River Nine Mile Falls, WA Spokane 1925 32.0 Little Falls Spokane River Ford, WA Big Bend 1910 35.2
Long Lake Spokane River Ford, WA Big Bend 1915 89.0
Upper Falls Spokane River Spokane, WA Spokane 1922 10.2
Cabinet Gorge Clark Fork River Clark Fork, ID CdA 1952 270.5
Noxon Rapids Clark Fork River Noxon, MT CdA 1959 610.0
Total 1079.9
TABLE 5: AVISTA RENEWABLE GENERATION RESOURCES.
Project Name Fuel Location Area
Project
Start Date
Maximum Capability (MW)F
Palouse Wind Thornton, WA Palouse 2012 104.0 Adams Neilson Solar Lind, WA Big Bend 2018 19.2 Total 123.2

TABLE 6: AVISTA THERMAL GENERATION RESOURCES.
Project Name Fuel Location Area Project Start Date
Maximum Capability (MW)F
Colstrip 3&4 (15%) Coal Colstrip, MT N/A 1984 247.0
Rathdrum (CT) Gas Rathdrum, ID CdA 1995 176.0
Northeast (CT) Gas Spokane, WA Spokane 1978 66.0
Boulder Park (IC) Gas Spokane, WA Spokane 2002 24.6
Coyote Springs 2 (CC) Gas Boardman, OR N/A 2003 317.5
Kettle Falls Wood Kettle Falls, WA Big Bend 1983 50.7 Kettle Falls (CT) Gas Kettle Falls, WA Big Bend 2002 11.0 Total 892.8
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1064 of 1105
For more information on Avista’s generation, please refer to the 2017 Integrated Resource
Plan.
A.2 TRANSMISSION SYSTEM
Avista owns and operates a system of over 2,200 miles of electric transmission facilities which
include approximately 685 miles of 230kV transmission lines and 1,527 miles of 115kV
transmission lines. Figure 6 illustrates Avista’s Transmission System within the region.

FIGURE 6 AVISTA TRANSMISSION LINE MAP
The Avista 230kV transmission lines are the backbone of Avista’s Transmission System and
consist of two networked systems centered near the Spokane/Coeur d’Alene area and the
Lewiston/Clarkston area.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1065 of 1105
TRANSMISSION MODELS
B.1 PLANNING CASE DESCRIPTION
Avista’s System Planning Group develops a set of base cases (Planning Cases) biannually to
model its Transmission Planner and Planning Coordinator areas as well as the regional
transmission system. The Planning Case development process outlined in the internal
document TP-SPP-04 – Data for Power System Modeling and Analysis is used which
includes using WECC approved base cases and applying steady state and dynamic data modifications as required to represent desired scenarios. The resulting Planning Cases represent a normal System condition (N-0). Planning Cases include the following:
• Existing facilities, new planned facilities and changes to existing facilities.
• Known outages of generation or transmission facilities with a duration of at greater than
six months are represented. Presently, Avista does not have long duration planned
outages.
• Forecasted real and reactive loads along with generation resources (supply or demand
side) are modeled as described in TP-SPP-07 – Loads and Resources Data for
Steady State and Dynamic Studies.
• Known commitments for Firm Transmission Service and Interchange are incorporated.
WECC Rated Paths are modeled with their published limits. Future commitments
exceeding the limits of WECC Rated Paths are not presently studied.
The following scenarios were developed to represent various seasonal conditions:
• Heavy Summer – this is a typical summer peak scenario where the Avista Balancing Authority Area load is at peak. The local hydro generation is at mid-summer output
levels, most thermal generation is on line, and moderate transfers are flowing into
Avista’s Balancing Authority Area. This scenario is limited by the summer thermal limits
on various elements of the transmission system, which helps to identify where the
system is near capacity.
• Light Summer – this is a typical summer night time scenario where the Avista Balancing
Authority Area load is at a minimum.
• Heavy Winter – this is a typical winter peak scenario where the Avista Balancing
Authority Area load is at peak. The local hydro generation is at late-winter output levels,
most thermal generation is on line, and moderate transfers are flowing into Avista’s
Balancing Authority Area. This scenario represents Avista heaviest load conditions, but
benefits from lower ambient temperature which increases the operating limits of the
various elements of the Transmission System and power factors near unity.
• Light Winter – this is a typical winter night time scenario where the Avista Balancing
Authority Area load is at a minimum.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1066 of 1105
• Light Spring – this is a typical late spring case that captures light loading conditions with
high levels of generation. The local hydro generation is near full capacity due to spring
runoff, local wind and solar generation is near full capacity, select thermal generation is
off line for maintenance, and moderate transfers are flowing out of Avista’s Balancing Authority Area. This scenario is also limited by the summer thermal limits on various elements of the transmission system, which helps to identify where the system is near capacity, due to power transfer.
• High East to West Transfer – this is a typical late spring case that captures light loading conditions with high levels of generation east of Avista’s Balancing Authority Area. This scenario brings both West of Hatwai (Path 6) and Montana to Northwest (Path 8) up to
their rated path limits. This scenario is also limited by the summer thermal limits on
various elements of the transmission system, which helps to identify where the system
is near capacity, due to power transfer.
• High West to East Transfer – this is a typical summer peak scenario where the Avista,
Idaho Power and Northwestern Energy Balancing Authority Area load is near peak. The
local hydro generation is at early-summer output levels, most thermal generation is off
line, and moderate transfers are flowing across Avista’s Balancing Authority Area to the
west. This scenario is limited by the summer thermal limits on various elements of the
transmission system, which helps to identify where the system is near capacity.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1067 of 1105

2021 Electric Integrated
Resource Plan

Appendix H – New Resource
Table for Transmission

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1068 of 1105
Resource Capacity YearResourceNoteLocationPORPODStartStopMWTotal
Wind Montana Colstrip/BPA or AVAT.NWMT AVA.SYS 1/1/2023 Indefinite 100.0 100.0
Wind Montana Colstrip/BPA or AVAT.NWMT AVA.SYS 1/1/2024 Indefinite 100.0 100.0
Kettle Falls Kettle Falls, WA AVA.SYS AVA.SYS 1/1/2026 Indefinite 12.0
Post Falls Post Falls AVA.SYS AVA.SYS 1/1/2026 Indefinite 8.0
Natural Gas Peaker Rathdrum, WA AVA.SYS AVA.SYS 11/1/2026 Indefinite 211.0 231.0
Wind Off-System Colstrip/BPA or AVAT.NWMT AVA.SYS 1/1/2028 Indefinite 100.0 100.0
Hydro Mid-C MIDC AVA.SYS 1/1/2031 Indefinite 75.0 75.0
Rathdrum Rathdrum, WA AVA.SYS AVA.SYS 1/1/2035 Indefinite 5.0 5.0
Natural Gas Peaker TBD AVA.SYS AVA.SYS 1/1/2036 Indefinite 87.0 87.0
Solar & Storage 100 MW Solar w/ 50 MW Storage TBD AVA.SYS AVA.SYS 1/1/2038 Indefinite 100.0 100.0
Wind TBD Colstrip/BPA or AVAT.NWMT AVA.SYS 1/1/2041 Indefinite 100.0
Natural Gas Peaker TBD AVA.SYS AVA.SYS 1/1/2041 Indefinite 36.0 136.0
Solar & Storage 117 MW Solar w/ 58 MW Storage TBD AVA.SYS AVA.SYS 1/1/2042 Indefinite 117.0 117.0
Solar & Storage 122 MW Solar w/ 61 MW Storage TBD AVA.SYS AVA.SYS 1/1/2043 Indefinite 122.0 122.0
Storage Liquid Air TBD AVA.SYS AVA.SYS 1/1/2044 Indefinite 12.0 12.0
Solar & Storage 149 MW Solar w/ 75 MW Storage TBD AVA.SYS AVA.SYS 1/1/2045 Indefinite 149.0
Storage Liquid Air TBD AVA.SYS AVA.SYS 1/1/2045 Indefinite 10.0 159.0
Total 1344.0 1344.0
Appendix H
New Resource Table For Transmission
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1069 of 1105

2021 Electric Integrated
Resource Plan

Appendix I – Publicly Available
Inputs and Models

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1070 of 1105
Appendix I
Avista Corp 2021 Electric IRP 1
Appendix I Content

The Company makes data input files in native format, models, and other various content used for its Integrated Resource
Planning process available to stakeholders. Non-confidential, non-proprietary IRP content can also be found at Integrated
Resource Planning (myavista.com). In a manner to further increase transparency and provide clarity for stakeholders, the
following table provides context on data files, models and other content included in Appendix I.

File Name Folder File Type Description of Content
DR Model Avista Integrated Opt-Demand Excel Final AEG model for opt-in demand response
DR Model Avista Integrated Opt-
Out 3_1_21
Demand
Response
Excel Final AEG model for opt-out demand response
programs.
DR Model Avista Stand Alone Demand Excel Final AEG model for stand-alone demand response
Avista 2020 CPA – Electric EE
Measure List
Energy Efficiency Excel List of residential, commercial and industrial energy
efficiency measures along with an introduction
Avista 2020 Electric CPA –
Summary and IRP
Energy Efficiency Excel Achievable technical potential energy savings, winter
peak savings, summary peak savings inputs used in
Home Electrification Conversion Load Forecast Excel

Regression, assumptions and summary of home
conversions if electrification were to occur and
Load Forecast Load Forecast Excel Energy forecast, peak forecast, retail sales, load split
Climate Shift Scenario Inputs Market Modeling
Inputs and Results
Excel 80-year regional hydro record from NPCC, NPCC
2024 economy load forecast with changing
CO2 Emissions by Market Modeling Excel Regional CO2 emission by year for the expected
CO2 Emissions by Year_SCC Market Modeling Excel Regional CO2 emission by year for the social cost of
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1071 of 1105
Appendix I
Avista Corp 2021 Electric IRP 2
High & Low Natural Gas Prices Market Modeling Excel High (95th percentile) and low (25th percentile)
Market Modeling Results Market Modeling
Inputs and Results
Excel Market modeling results to include stochastic off-
peak/on-peak/flat Mid-C prices, stochastic
greenhouse gas, hourly Mid-C prices, stochastic
historical regional resource dispatch, deterministic
hourly Mid-C prices, deterministic monthly Mid-C
prices scenarios, deterministic annual greenhouse
gas emissions and deterministic regional resource
Natural Gas Prices Market Modeling
Inputs and Results
Excel Monthly natural gas price forecast used for the IRP,
both stochastic and deterministic, as well as basin
Regional Generation
Analysis_ClimateShift_2021_IR
Market Modeling
Inputs and Results
Excel Regional generation analysis by fuel type by state.
Regional Generation
Analysis_Expected-
Market Modeling
Inputs and Results
Excel Regional deterministic generation analysis by fuel
type by state.
Regional Generation
Analysis_Expected-
Market Modeling
Inputs and Results
Excel Regional stochastic generation analysis by fuel type
by state.
Regional Generation
Analysis_HighPrice_2021_IRP
Market Modeling
Inputs and Results
Excel Regional generation analysis by fuel type by state
using the high price scenario.
Regional Generation Market Modeling Excel Regional generation analysis by fuel type by state
Regional Generation
Analysis_SCC-Case_2021_IRP
Excel Regional generation analysis by fuel type by state
using the SCC scenario.
Social Cost of Carbon Market Modeling Excel Social cost of carbon in 2007 and 2019 dollars,
Emissions_Summary_073020 Other Files Excel Avista owned resource emissions summary for
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1072 of 1105
Appendix I
Avista Corp 2021 Electric IRP 3
Named Populations Other Files Excel State FIPS codes, county codes, socioeconomic and
sensitive population ratings (1-10 with 10 being the
Upstream Emission Calculation Other Files Excel Upstream emission calculation for gas and power
1_PRiSM_7.0_GUROBI_12072
0_IRP_PRS_DRAFT_Determini
stic
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Least reasonable cost, PRS, deterministic scenario.
Includes a summary of resource selected, financial
summary, clean goal progress, loads & resources,
demand response, resource data, energy efficiency
selected, Aurora resource results, transmission
annual revenue requirement from amortization
model, annual cost of resource options, resources
(MWh), hydro & contracts market value, stochastic
variable cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
1_PRiSM_7.0_GUROBI_12072
0_IRP_PRS_DRAFT_HighNGPr
ice
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Least reasonable cost, PRS, high natural gas price
scenario. Includes a summary of resource selected,
financial summary, clean goal progress, loads &
resources, demand response, resource data, energy
efficiency selected, Aurora resource results,
transmission annual revenue requirement from
amortization model, annual cost of resource options,
resources (MWh), hydro & contracts market value,
stochastic variable cost of risk, general assumptions,
regional emissions, conservation load value ($/MW)
1_PRiSM_7.0_GUROBI_12072
0_IRP_PRS_DRAFT_LowNGPri
ce
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Least reasonable cost, PRS, low natural gas price
scenario. Includes a summary of resource selected,
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1073 of 1105
Appendix I
Avista Corp 2021 Electric IRP 4
resources, demand response, resource data, energy
efficiency selected, Aurora resource results,
transmission annual revenue requirement from
amortization model, annual cost of resource options,
resources (MWh), hydro & contracts market value,
stochastic variable cost of risk, general assumptions,
regional emissions, conservation load value ($/MW)
1_PRiSM_7.0_GUROBI_12072
0_IRP_PRS_DRAFT_SCC
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Least reasonable cost, PRS, social cost of carbon
scenario. Includes a summary of resource selected,
financial summary, clean goal progress, loads &
resources, demand response, resource data, energy
efficiency selected, Aurora resource results,
transmission annual revenue requirement from
amortization model, annual cost of resource options,
resources (MWh), hydro & contracts market value,
stochastic variable cost of risk, general assumptions,
regional emissions, conservation load value ($/MW)
1a_PRiSM_7.0_GUROBI_1207
20_IRP_PRS_DRAFT_ClimateS
hift
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Climate shift scenario, deterministic study, re-
optimized. Includes a summary of resource selected,
financial summary, clean goal progress, loads &
resources, demand response, resource data, energy
efficiency selected, Aurora resource results,
transmission annual revenue requirement from
amortization model, annual cost of resource options,
resources (MWh), hydro & contracts market value,
stochastic variable cost of risk, general assumptions,
regional emissions, conservation load value ($/MW)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1074 of 1105
Appendix I
Avista Corp 2021 Electric IRP 5
1b_PRiSM_7.0_GUROBI_1207
20_IRP_PRS_DRAFT_SCC
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Least reasonable cost, PRS, social cost of carbon
scenario, re-optimized for SCC. Includes a summary
of resource selected, financial summary, clean goal
progress, loads & resources, demand response,
resource data, energy efficiency selected, Aurora
resource results, transmission annual revenue
requirement from amortization model, annual cost of
resource options, resources (MWh), hydro &
contracts market value, stochastic variable cost of
risk, general assumptions, regional emissions,
3_PRiSM_7.0_GUROBI_12072
0_IRP_PRS_DRAFT_Determini
stic
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Baseline 2 portfolio, deterministic. Includes a
summary of resource selected, financial summary,
clean goal progress, loads & resources, demand
response, resource data, energy efficiency selected,
Aurora resource results, transmission annual
revenue requirement from amortization model,
annual cost of resource options, resources (MWh),
hydro & contracts market value, stochastic variable
cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
3_PRiSM_7.0_GUROBI_12072
0_IRP_PRS_DRAFT_HighNGPr
ice
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Baseline 2 portfolio, high gas price scenario.
Includes a summary of resource selected, financial
summary, clean goal progress, loads & resources,
demand response, resource data, energy efficiency
selected, Aurora resource results, transmission
annual revenue requirement from amortization
model, annual cost of resource options, resources
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1075 of 1105
Appendix I
Avista Corp 2021 Electric IRP 6
variable cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
3_PRiSM_7.0_GUROBI_12072
0_IRP_PRS_DRAFT_LowNGPri
ce
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Baseline 2 portfolio, low gas price scenario. Includes
a summary of resource selected, financial summary,
clean goal progress, loads & resources, demand
response, resource data, energy efficiency selected,
Aurora resource results, transmission annual
revenue requirement from amortization model,
annual cost of resource options, resources (MWh),
hydro & contracts market value, stochastic variable
cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
3_PRiSM_7.0_GUROBI_12072
0_IRP_PRS_DRAFT_SCC
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Baseline 2 portfolio, social cost of carbon scenario.
Includes a summary of resource selected, financial
summary, clean goal progress, loads & resources,
demand response, resource data, energy efficiency
selected, Aurora resource results, transmission
annual revenue requirement from amortization
model, annual cost of resource options, resources
(MWh), hydro & contracts market value, stochastic
variable cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
5_PRiSM_7.0_GUROBI_12072
0_IRP_PRS_DRAFT_Determini
stic
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
2027 clean resource plan, add clean energy
resources to = 100% retail sales, deterministic
scenario. Includes a summary of resource selected,
financial summary, clean goal progress, loads &
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1076 of 1105
Appendix I
Avista Corp 2021 Electric IRP 7
efficiency selected, Aurora resource results,
transmission annual revenue requirement from
amortization model, annual cost of resource options,
resources (MWh), hydro & contracts market value,
stochastic variable cost of risk, general assumptions,
regional emissions, conservation load value ($/MW)
5_PRiSM_7.0_GUROBI_12072
0_IRP_PRS_DRAFT_HighNGPr
ice
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
2027 clean resource plan, add clean energy
resources to = 100% retail sales, high natural gas
price scenario. Includes a summary of resource
selected, financial summary, clean goal progress,
loads & resources, demand response, resource
data, energy efficiency selected, Aurora resource
results, transmission annual revenue requirement
from amortization model, annual cost of resource
options, resources (MWh), hydro & contracts market
value, stochastic variable cost of risk, general
assumptions, regional emissions, conservation load
5_PRiSM_7.0_GUROBI_12072
0_IRP_PRS_DRAFT_LowNGPri
ce
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
2027 clean resource plan, add clean energy
resources to = 100% retail sales, low natural gas
price scenario. Includes a summary of resource
selected, financial summary, clean goal progress,
loads & resources, demand response, resource
data, energy efficiency selected, Aurora resource
results, transmission annual revenue requirement
from amortization model, annual cost of resource
options, resources (MWh), hydro & contracts market
value, stochastic variable cost of risk, general
assumptions, regional emissions, conservation load
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1077 of 1105
Appendix I
Avista Corp 2021 Electric IRP 8
5_PRiSM_7.0_GUROBI_12072
0_IRP_PRS_DRAFT_SCC
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
2027 clean resource plan, add clean energy
resources to = 100% retail sales, social cost of
carbon scenario. Includes a summary of resource
selected, financial summary, clean goal progress,
loads & resources, demand response, resource
data, energy efficiency selected, Aurora resource
results, transmission annual revenue requirement
from amortization model, annual cost of resource
options, resources (MWh), hydro & contracts market
value, stochastic variable cost of risk, general
assumptions, regional emissions, conservation load
6_PRiSM_7.0_GUROBI_12072
0_IRP_PRS_DRAFT_Determini
stic
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
2045 clean resource plan, add clean energy
resources to = 100% retail sales, no new thermal
resource, existing thermal resource retire by 2044,
long lake and cabinet upgrades turned on,
deterministic scenario. Includes a summary of
resource selected, financial summary, clean goal
progress, loads & resources, demand response,
resource data, energy efficiency selected, Aurora
resource results, transmission annual revenue
requirement from amortization model, annual cost of
resource options, resources (MWh), hydro &
contracts market value, stochastic variable cost of
risk, general assumptions, regional emissions,
6_PRiSM_7.0_GUROBI_12072
0_IRP_PRS_DRAFT_HighNGPr
ice
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
2045 clean resource plan, add clean energy
resources to = 100% retail sales, no new thermal
resource, existing thermal resource retire by 2044,
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1078 of 1105
Appendix I
Avista Corp 2021 Electric IRP 9
natural gas price scenario. Includes a summary of
resource selected, financial summary, clean goal
progress, loads & resources, demand response,
resource data, energy efficiency selected, Aurora
resource results, transmission annual revenue
requirement from amortization model, annual cost of
resource options, resources (MWh), hydro &
contracts market value, stochastic variable cost of
risk, general assumptions, regional emissions,
6_PRiSM_7.0_GUROBI_12072
0_IRP_PRS_DRAFT_LowNGPri
ce
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
2045 clean resource plan, add clean energy
resources to = 100% retail sales, no new thermal
resource, existing thermal resource retire by 2044,
long lake and cabinet upgrades turned on, low
natural gas price scenario. Includes a summary of
resource selected, financial summary, clean goal
progress, loads & resources, demand response,
resource data, energy efficiency selected, Aurora
resource results, transmission annual revenue
requirement from amortization model, annual cost of
resource options, resources (MWh), hydro &
contracts market value, stochastic variable cost of
risk, general assumptions, regional emissions,
6_PRiSM_7.0_GUROBI_12072
0_IRP_PRS_DRAFT_SCC
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
2045 clean resource plan, add clean energy
resources to = 100% retail sales, no new thermal
resource, existing thermal resource retire by 2044,
long lake and cabinet upgrades turned on, social
cost of carbon scenario. Includes a summary of
resource selected, financial summary, clean goal
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1079 of 1105
Appendix I
Avista Corp 2021 Electric IRP 10
resource data, energy efficiency selected, Aurora
resource results, transmission annual revenue
requirement from amortization model, annual cost of
resource options, resources (MWh), hydro &
contracts market value, stochastic variable cost of
risk, general assumptions, regional emissions,
15_PRiSM_7.0_GUROBI_1207
20_IRP_PRS_DRAFT_Determin
istic
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Colstrip retire 2025, deterministic scenario. Includes
a summary of resource selected, financial summary,
clean goal progress, loads & resources, demand
response, resource data, energy efficiency selected,
Aurora resource results, transmission annual
revenue requirement from amortization model,
annual cost of resource options, resources (MWh),
hydro & contracts market value, stochastic variable
cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
15_PRiSM_7.0_GUROBI_1207
20_IRP_PRS_DRAFT_HighNG
Price
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Colstrip retire 2025, high natural gas price scenario.
Includes a summary of resource selected, financial
summary, clean goal progress, loads & resources,
demand response, resource data, energy efficiency
selected, Aurora resource results, transmission
annual revenue requirement from amortization
model, annual cost of resource options, resources
(MWh), hydro & contracts market value, stochastic
variable cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1080 of 1105
Appendix I
Avista Corp 2021 Electric IRP 11
15_PRiSM_7.0_GUROBI_1207
20_IRP_PRS_DRAFT_LowNGP
rice
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Colstrip retire 2025, low natural gas price scenario.
Includes a summary of resource selected, financial
summary, clean goal progress, loads & resources,
demand response, resource data, energy efficiency
selected, Aurora resource results, transmission
annual revenue requirement from amortization
model, annual cost of resource options, resources
(MWh), hydro & contracts market value, stochastic
variable cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
15_PRiSM_7.0_GUROBI_1207
20_IRP_PRS_DRAFT_SCC
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Colstrip retire 2025, social cost of carbon scenario.
Includes a summary of resource selected, financial
summary, clean goal progress, loads & resources,
demand response, resource data, energy efficiency
selected, Aurora resource results, transmission
annual revenue requirement from amortization
model, annual cost of resource options, resources
(MWh), hydro & contracts market value, stochastic
variable cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
16_PRiSM_7.0_GUROBI_1207
20_IRP_PRS_DRAFT_Determin
istic
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Colstrip retire 2035, deterministic scenario. Includes
a summary of resource selected, financial summary,
clean goal progress, loads & resources, demand
response, resource data, energy efficiency selected,
Aurora resource results, transmission annual
revenue requirement from amortization model,
annual cost of resource options, resources (MWh),
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1081 of 1105
Appendix I
Avista Corp 2021 Electric IRP 12
cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
16_PRiSM_7.0_GUROBI_1207
20_IRP_PRS_DRAFT_HighNG
Price
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Colstrip retire 2035, high natural gas price scenario.
Includes a summary of resource selected, financial
summary, clean goal progress, loads & resources,
demand response, resource data, energy efficiency
selected, Aurora resource results, transmission
annual revenue requirement from amortization
model, annual cost of resource options, resources
(MWh), hydro & contracts market value, stochastic
variable cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
16_PRiSM_7.0_GUROBI_1207
20_IRP_PRS_DRAFT_LowNGP
rice
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Colstrip retire 2035, low natural gas price scenario.
Includes a summary of resource selected, financial
summary, clean goal progress, loads & resources,
demand response, resource data, energy efficiency
selected, Aurora resource results, transmission
annual revenue requirement from amortization
model, annual cost of resource options, resources
(MWh), hydro & contracts market value, stochastic
variable cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
16_PRiSM_7.0_GUROBI_1207
20_IRP_PRS_DRAFT_SCC
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Colstrip retire 2035, social cost of carbon scenario.
Includes a summary of resource selected, financial
summary, clean goal progress, loads & resources,
demand response, resource data, energy efficiency
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1082 of 1105
Appendix I
Avista Corp 2021 Electric IRP 13
annual revenue requirement from amortization
model, annual cost of resource options, resources
(MWh), hydro & contracts market value, stochastic
variable cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
17_PRiSM_7.0_GUROBI_1207
20_IRP_PRS_DRAFT_Determin
istic
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Colstrip retire 2045, deterministic scenario. Includes
a summary of resource selected, financial summary,
clean goal progress, loads & resources, demand
response, resource data, energy efficiency selected,
Aurora resource results, transmission annual
revenue requirement from amortization model,
annual cost of resource options, resources (MWh),
hydro & contracts market value, stochastic variable
cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
17_PRiSM_7.0_GUROBI_1207
20_IRP_PRS_DRAFT_HighNG
Price
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Colstrip retire 2045, high natural gas price scenario.
Includes a summary of resource selected, financial
summary, clean goal progress, loads & resources,
demand response, resource data, energy efficiency
selected, Aurora resource results, transmission
annual revenue requirement from amortization
model, annual cost of resource options, resources
(MWh), hydro & contracts market value, stochastic
variable cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
17_PRiSM_7.0_GUROBI_1207
20_IRP_PRS_DRAFT_LowNGP
PRiSM Model
Files- Portfolio
Excel PRiSM model - must have Gurobi license to run.
Colstrip retire 2045, low natural gas price scenario.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1083 of 1105
Appendix I
Avista Corp 2021 Electric IRP 14
summary, clean goal progress, loads & resources,
demand response, resource data, energy efficiency
selected, Aurora resource results, transmission
annual revenue requirement from amortization
model, annual cost of resource options, resources
(MWh), hydro & contracts market value, stochastic
variable cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
17_PRiSM_7.0_GUROBI_1207
20_IRP_PRS_DRAFT_SCC
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Colstrip retire 2045, social cost of carbon scenario.
Includes a summary of resource selected, financial
summary, clean goal progress, loads & resources,
demand response, resource data, energy efficiency
selected, Aurora resource results, transmission
annual revenue requirement from amortization
model, annual cost of resource options, resources
(MWh), hydro & contracts market value, stochastic
variable cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
1_PRiSM_7.0_GUROBI_12072
0_IRP_PRS
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
Least reasonable cost. preferred resource strategy.
Includes a summary of resource selected, financial
summary, clean goal progress, loads & resources,
demand response, resource data, energy efficiency
selected, Aurora resource results, transmission
annual revenue requirement from amortization
model, annual cost of resource options, resources
(MWh), hydro & contracts market value, stochastic
variable cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1084 of 1105
Appendix I
Avista Corp 2021 Electric IRP 15
2_PRiSM_7.0_GUROBI_12072
0_IRP_Baseline1
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
Baseline 1, removes clean energy targets in
Washington. Includes a summary of resource
selected, financial summary, clean goal progress,
loads & resources, demand response, resource
data, energy efficiency selected, Aurora resource
results, transmission annual revenue requirement
from amortization model, annual cost of resource
options, resources (MWh), hydro & contracts market
value, stochastic variable cost of risk, general
assumptions, regional emissions, conservation load
3_PRiSM_7.0_GUROBI_12072
0_IRP_Baseline2
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
Baseline 2, no clean goal, no SCC, EE held
constant, existing resources held constant, remove
flex plant as option due to size even though it’s
preferred. Includes a summary of resource selected,
financial summary, clean goal progress, loads &
resources, demand response, resource data, energy
efficiency selected, Aurora resource results,
transmission annual revenue requirement from
amortization model, annual cost of resource options,
resources (MWh), hydro & contracts market value,
stochastic variable cost of risk, general assumptions,
regional emissions, conservation load value ($/MW)
4_PRiSM_7.0_GUROBI_12072
0_IRP_Baseline3
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
Baseline 3, no clean goal, no SCC, EE held
constant, existing resources held constant. Includes
a summary of resource selected, financial summary,
clean goal progress, loads & resources, demand
response, resource data, energy efficiency selected,
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1085 of 1105
Appendix I
Avista Corp 2021 Electric IRP 16
revenue requirement from amortization model,
annual cost of resource options, resources (MWh),
hydro & contracts market value, stochastic variable
cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
5_PRiSM_7.0_GUROBI_12072
0_IRP_2027 CRP
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
2027 clean resource plan, add clean energy
resources to = 100% retail sales. Includes a
summary of resource selected, financial summary,
clean goal progress, loads & resources, demand
response, resource data, energy efficiency selected,
Aurora resource results, transmission annual
revenue requirement from amortization model,
annual cost of resource options, resources (MWh),
hydro & contracts market value, stochastic variable
cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
6_PRiSM_7.0_GUROBI_12072
0_IRP_2045 CRP
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
2045 clean resource plan, add clean energy
resources to = 100% retail sales, no new thermal
resource, existing thermal resource retire by 2044,
long lake and cabinet upgrades turned on. Includes
a summary of resource selected, financial summary,
clean goal progress, loads & resources, demand
response, resource data, energy efficiency selected,
Aurora resource results, transmission annual
revenue requirement from amortization model,
annual cost of resource options, resources (MWh),
hydro & contracts market value, stochastic variable
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1086 of 1105
Appendix I
Avista Corp 2021 Electric IRP 17
emissions, conservation load value ($/MW) and new
6b_PRiSM_7.0_GUROBI_1207
20_IRP_2045 CRP
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
2045 clean resource plan, add clean energy
resources to = 100%, Colstrip exits in 2022 retail
sales, no new thermal resource, existing thermal
resource retire by 2044, long lake and cabinet
upgrades turned on. Includes a summary of resource
selected, financial summary, clean goal progress,
loads & resources, demand response, resource
data, energy efficiency selected, Aurora resource
results, transmission annual revenue requirement
from amortization model, annual cost of resource
options, resources (MWh), hydro & contracts market
value, stochastic variable cost of risk, general
assumptions, regional emissions, conservation load
7_PRiSM_7.0_GUROBI_12072
0_IRP_SCC Applied to ID
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
Social cost of carbon applied to Idaho, EE held
constant. Includes a summary of resource selected,
financial summary, clean goal progress, loads &
resources, demand response, resource data, energy
efficiency selected, Aurora resource results,
transmission annual revenue requirement from
amortization model, annual cost of resource options,
resources (MWh), hydro & contracts market value,
stochastic variable cost of risk, general assumptions,
regional emissions, conservation load value ($/MW)
8_PRiSM_7.0_GUROBI_12072
0_IRP_Low Load Forecast
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
Low load forecast scenario, EE held constant from
PRS. Includes a summary of resource selected,
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1087 of 1105
Appendix I
Avista Corp 2021 Electric IRP 18
resources, demand response, resource data, energy
efficiency selected, Aurora resource results,
transmission annual revenue requirement from
amortization model, annual cost of resource options,
resources (MWh), hydro & contracts market value,
stochastic variable cost of risk, general assumptions,
regional emissions, conservation load value ($/MW)
9_PRiSM_7.0_GUROBI_12072
0_IRP_High Load Forecast
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
High load forecast scenario, EE held constant from
PRS. Includes a summary of resource selected,
financial summary, clean goal progress, loads &
resources, demand response, resource data, energy
efficiency selected, Aurora resource results,
transmission annual revenue requirement from
amortization model, annual cost of resource options,
resources (MWh), hydro & contracts market value,
stochastic variable cost of risk, general assumptions,
regional emissions, conservation load value ($/MW)
10_PRiSM_7.0_GUROBI_1207
20_RA Market
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
Resource adequacy market scenario, uses RA
market planning requirements rather than Avista’s,
includes change to existing resources and changes
to peak credits for new resources. Includes a
summary of resource selected, financial summary,
clean goal progress, loads & resources, demand
response, resource data, energy efficiency selected,
Aurora resource results, transmission annual
revenue requirement from amortization model,
annual cost of resource options, resources (MWh),
hydro & contracts market value, stochastic variable
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1088 of 1105
Appendix I
Avista Corp 2021 Electric IRP 19
emissions, conservation load value ($/MW) and new
11_PRiSM_7.0_GUROBI_1207
20_IRP_Electirication 1
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
Electrification scenario 1, forecast of additional load
due to natural gas customers moving to electric,
uses Avista forecast on load changes, updates EE
programs & DR for additional opportunities,
adjustments made to load value & retail sales.
Includes a summary of resource selected, financial
summary, clean goal progress, loads & resources,
demand response, resource data, energy efficiency
selected, Aurora resource results, transmission
annual revenue requirement from amortization
model, annual cost of resource options, resources
(MWh), hydro & contracts market value, stochastic
variable cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
12_PRiSM_7.0_GUROBI_1207
20_IRP_Electirication 2
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
Electrification scenario 2 – hybrid scenario, forecast
of additional load due to natural gas customers
moving to electric, uses Avista forecast on load
changes, updates EE programs & DR for additional
opportunities, adjustments made to load value &
retail sales. Includes a summary of resource
selected, financial summary, clean goal progress,
loads & resources, demand response, resource
data, energy efficiency selected, Aurora resource
results, transmission annual revenue requirement
from amortization model, annual cost of resource
options, resources (MWh), hydro & contracts market
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1089 of 1105
Appendix I
Avista Corp 2021 Electric IRP 20
assumptions, regional emissions, conservation load
13_PRiSM_7.0_GUROBI_1207
20_IRP_Electirication 3
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
Electrification scenario 3 – high efficiency, forecast
of additional load due to natural gas customers
moving to electric, uses Avista forecast on load
changes, updates EE programs & DR for additional
opportunities, adjustments made to load value &
retail sales. Includes a summary of resource
selected, financial summary, clean goal progress,
loads & resources, demand response, resource
data, energy efficiency selected, Aurora resource
results, transmission annual revenue requirement
from amortization model, annual cost of resource
options, resources (MWh), hydro & contracts market
value, stochastic variable cost of risk, general
assumptions, regional emissions, conservation load
14_PRiSM_7.0_GUROBI_1207
20_IRP_2xSCC
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
Social cost of carbon times 2, doubles SCC for
Washington – least cost strategy with this
assumption. Includes a summary of resource
selected, financial summary, clean goal progress,
loads & resources, demand response, resource
data, energy efficiency selected, Aurora resource
results, transmission annual revenue requirement
from amortization model, annual cost of resource
options, resources (MWh), hydro & contracts market
value, stochastic variable cost of risk, general
assumptions, regional emissions, conservation load
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1090 of 1105
Appendix I
Avista Corp 2021 Electric IRP 21
15_PRiSM_7.0_GUROBI_1207
20_IRP_Colstrip2025
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
Colstrip retire in 2025. Includes a summary of
resource selected, financial summary, clean goal
progress, loads & resources, demand response,
resource data, energy efficiency selected, Aurora
resource results, transmission annual revenue
requirement from amortization model, annual cost of
resource options, resources (MWh), hydro &
contracts market value, stochastic variable cost of
risk, general assumptions, regional emissions,
16_PRiSM_7.0_GUROBI_1207
20_IRP_Colstrip2035
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
Colstrip retire in 2035. Includes a summary of
resource selected, financial summary, clean goal
progress, loads & resources, demand response,
resource data, energy efficiency selected, Aurora
resource results, transmission annual revenue
requirement from amortization model, annual cost of
resource options, resources (MWh), hydro &
contracts market value, stochastic variable cost of
risk, general assumptions, regional emissions,
17_PRiSM_7.0_GUROBI_1207
20_IRP_Colstrip2045
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
Colstrip retire in 2045. Includes a summary of
resource selected, financial summary, clean goal
progress, loads & resources, demand response,
resource data, energy efficiency selected, Aurora
resource results, transmission annual revenue
requirement from amortization model, annual cost of
resource options, resources (MWh), hydro &
contracts market value, stochastic variable cost of
risk, general assumptions, regional emissions,
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1091 of 1105
Appendix I
Avista Corp 2021 Electric IRP 22
18_PRiSM_7.0_GUROBI_1207
20_IRP_2045 100 Delivered
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run. Not
optimized, add clean resources and storage to meet
delivery to load requirements. Includes a summary of
resource selected, financial summary, clean goal
progress, loads & resources, demand response,
resource data, energy efficiency selected, Aurora
resource results, transmission annual revenue
requirement from amortization model, annual cost of
resource options, resources (MWh), hydro &
contracts market value, stochastic variable cost of
risk, general assumptions, regional emissions,
19_PRiSM_7.0_GUROBI_1207
20_IRP_SCC_PS
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
Social cost of carbon applied to net purchases,
includes net purchase included storage purchases.
Includes a summary of resource selected, financial
summary, clean goal progress, loads & resources,
demand response, resource data, energy efficiency
selected, Aurora resource results, transmission
annual revenue requirement from amortization
model, annual cost of resource options, resources
(MWh), hydro & contracts market value, stochastic
variable cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
20_PRiSM_7.0_GUROBI_1207
20_IRP_EE-Avg Mrkt Emissions
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run. Use
average market emission rate rather than
incremental for EE SCC calculation, all other PRS
inputs/constraints are the same, this study is
conducted iteratively, meaning resulting EE is added
back in the model to adjust loads and re-run.
Includes a summary of resource selected, financial
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1092 of 1105
Appendix I
Avista Corp 2021 Electric IRP 23
demand response, resource data, energy efficiency
selected, Aurora resource results, transmission
annual revenue requirement from amortization
model, annual cost of resource options, resources
(MWh), hydro & contracts market value, stochastic
variable cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
21_PRiSM_7.0_GUROBI_1207
20_IRP_PRS_Draft_Maximum
Benefit
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
Washington maximum benefit. Includes a summary
of resource selected, financial summary, clean goal
progress, loads & resources, demand response,
resource data, energy efficiency selected, Aurora
resource results, transmission annual revenue
requirement from amortization model, annual cost of
resource options, resources (MWh), hydro &
contracts market value, stochastic variable cost of
risk, general assumptions, regional emissions,
PRiSM Draft Results_120720 PRiSM Model
Files- Portfolio
Studies
Excel Scenario list, summary data, sensitivity summary,
sensitivity data, summary resources PRS, existing
resources, annual summary by scenario, summary
table of PVRR ($ Mill) by state and select years, cost
vs risk by scenario, clean goal, GHG emissions,
PRiSM Model Guide PRiSM Model
Files- Portfolio
Word User guide for the PRiSM models.
2021 IRP New Supply Side Appendix I Excel Supply side resource option assumptions for cost,

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1093 of 1105

2021 Electric Integrated
Resource Plan

Appendix J – Confidential Inputs
and Models

Idaho – Confidential pursuant to Sections 74-109, Idaho Code
Washington – Confidential per WAC 480-07-160

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1094 of 1105
Appendix J
Avista Corp 2021 Electric IRP 1
Appendix J Content

The Company makes data input files in native format, models, and other various content used for its Integrated Resource
Planning process available to stakeholders. Non-confidential, non-proprietary IRP content can also be found at Integrated
Resource Planning (myavista.com). In a manner to further increase transparency and provide clarity for stakeholders, the
following table provides context on data files, models and other content included in Appendix J.

File Name Folder File Type Description of Content
ARAM Model Guide ARAM-Reliability Word User guide for ARAM models.
ARAM_2021_IRP_2025_No_Ad
ditions_121020_With Colstrip
ARAM-Reliability
Studies
Excel Reliability study considering no additions, with
Colstrip for select year.
ARAM_2021_IRP_2025_No_Ad ARAM-Reliability Excel Reliability study considering no additions, without
ARAM_2021_IRP_2025_PRS ARAM-Reliability Excel Reliability study considering PRS for select year.
ARAM_2021_IRP_2030_330 ARAM-Reliability Excel Reliability study considering 330 market and PRS
ARAM_2021_IRP_2030_330 ARAM-Reliability Excel Reliability study considering 330 market scenario 5
ARAM_2021_IRP_2030_330 ARAM-Reliability Excel Reliability study considering 330 market scenario 10
ARAM_2021_IRP_2030_330 ARAM-Reliability Excel Reliability study considering 330 market scenario 16
ARAM_2021_IRP_2030_333MW ARAM-Reliability Excel Reliability study considering 333 MW of CTs and
ARAM_2021_IRP_2040_No_Ad ARAM-Reliability Excel Reliability study considering no additions, for select
ARAM_2021_IRP_2040_PRS ARAM-Reliability Excel Reliability study considering PRS for select year.
ARAM_2021_IRP_2040_PRS_3 ARAM-Reliability Excel Reliability study considering PRS and 3 units for
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1095 of 1105
Appendix J
Avista Corp 2021 Electric IRP 2
ARAM_2021_IRP_2040_Scenari ARAM-Reliability Excel Reliability study considering scenario 6-CR2045 for
2021 IRP Aurora Files Aurora Deterministic model updated for climate change
2021 IRP
Deterministic_High_NG_Prices
Aurora Files Aurora Deterministic model updated for high natural gas
prices used for 2021 IRP.
2021 IRP Aurora Files Aurora Deterministic model updated for low natural gas
2021 IRP
Deterministic_No_AVA_EE
Aurora Files Aurora Deterministic model updated for no Avista energy
efficiency used for 2021 IRP.
2021 IRP Deterministic_SCC Aurora Files Aurora Deterministic model updated for social cost of
IRP_2021_US_Canada_DB_201 Aurora Files Database Aurora database for US/Canada
New Resources_Expected Case Aurora Files Excel Annual table inputs, summary, resource tables
DR Input Generator – Avista Appendix J Excel Demand response participation rates, impact,

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1096 of 1105

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1097 of 1105

2021 Electric Integrated
Resource Plan

Appendix K – Load Forecast
Supplement

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1098 of 1105
Appendix K Page 1
Appendix K
Climate Change

The process of integrating climate change into the load forecast starts with estimating the
long-run trend in the 20-year average of annual heating degree days (HDD) and cooling
degree days (CDD). Ideally, trending the 20-year moving average introduces climate
change while still maintain a smoothed measure of normal (average) weather. Figure K.1
demonstrates the issues that need to be considered when choosing a method to introduce
climate change using HDD.
Figure K.1: Issues Related to Forecasted HDD and CDD

Line A reflects the most recent 20-year moving average (HDD20) ending with the current
calendar year (yc). In the current IRP, this is the 2000-2019 period. Without a climate
change adjustment, Line A is the assumed normal weather over Yc+n. Line A will only shift
up or down as the 20-year average is updated with a new year of HDD data. If climate
change is occurring, then line A will gradually shift down over time along the vertical axis.

A forward-looking climate change adjustment to line A requires introducing a trended
moving going forward in time—this is shown by line B or C. However, a method that
produces line C is problematic because, compared to line B, it introduces a significant
amount of year-to-year variation over the forecast period. In turn, this produces significant
amount of volatility in forecasted load, revenues, and earnings that may not be acceptable
to the planning process. However, even if a method produces a smooth trend over the
forecast horizon, another problem can arise. Specifically, if the method that produces line
B generates large shifts in the slope and intercept between forecast runs (i.e., the forecast
completed in year y versus the forecast completed in year y+1), this method will also
yc yc+n
HDD20

B*

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1099 of 1105
Appendix K Page 2
produce a level of volatility that may not be acceptable. This is shown by line B* compared
to line B. This analysis shows that the method chosen should be stable over and between
forecast runs, yet still capture the current best guess path of climate change over the
forecast horizon.

The method used by Avista, starts with an analysis of the 20-year moving average of HDD
and CDD using a 20-year moving average time-series going back to 1967. In other words,
the first observation in the time series is the 20-year moving average for the period 1948-
1967, where 1948 is the start of Avista’s (AVA) annual billing adjusted HDD data
(discussed above). After analyzing the time-series behavior of both series, the following
time series regression equations are estimated:

[1A] ∆𝐻𝐷𝐷,= 𝛿+ 𝜃∆𝐻𝐷𝐷,+ 𝜃∆𝐻𝐷𝐷,+ 𝜃∆𝐻𝐷𝐷,+ 𝜃∆𝐻𝐷𝐷,+
𝜃∆𝐻𝐷𝐷,+ 𝜖
[2A] ∆𝐶𝐷𝐷,= 𝛿+ 𝛾∆𝐶𝐷𝐷,+ 𝛾∆𝐶𝐷𝐷,+ 𝛾∆𝐶𝐷𝐷,+ 𝛾∆𝐶𝐷𝐷,+
𝛾∆𝐶𝐷𝐷,+ 𝜖
Here, εy is a white noise, mean zero error term.
Assuming model stationarity, the constant value δ can be used to calculate the long-run
expected change in annual HDD and CDD:
[3A] 𝜇∆=()
[4A] 𝜇∆=()
This can then be applied to the current 20-year moving average to generate trended
values out a total of N years:
[5A] 𝐹(𝐻𝐷𝐷,) = 𝐻𝐷𝐷,+ 𝑛𝜇∆ 𝑓𝑜𝑟 𝑛 = 1, …, 𝑁

[6A] 𝐹(𝐶𝐷𝐷,) = 𝐶𝐷𝐷,+ 𝑛𝜇∆ 𝑓𝑜𝑟 𝑛 = 1,… ,𝑁
For most IRPs, N = 25. If monthly values are needed over the forecast period, then the
annual values can be allocated monthly as follows:
[7A] 𝐹(𝐻𝐷𝐷,,) = ℎ𝐹(𝐻𝐷𝐷,) 𝑤ℎ𝑒𝑟𝑒 ℎ=
∑, 𝑓𝑜𝑟 𝑡 = 𝐽𝑎𝑛, …,𝐷𝑒𝑐
[8A] 𝐹(𝐶𝐷𝐷,,) = 𝑐̅𝐹(𝐶𝐷𝐷,) 𝑤ℎ𝑒𝑟𝑒 𝑐̅=
∑,𝑓𝑜𝑟 𝑡 = 𝐽𝑎𝑛,…,𝐷𝑒𝑐

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1100 of 1105
Appendix K Page 3
Here, ℎ and 𝑐̅ are the 20-year average share of HDD and CDD, respectively, in month
t. These monthly values can be used to convert the annual IRP simulation model forecasts
to monthly values or, alternatively, adding climate change to the peak load forecast. It
should be noted that an analysis of the share of HDD and CDD by month going back to
1948 do not show any apparent trends. This suggests, even under climate change, the
relative allocation of HDD and CDD across the months each year will not change
significantly going forward.
Returning to the annual, trended moving average forecasts of HDD and CDD, those can
be used to estimate the long-run impact on annual residential UPC (UPCr,y) in the face of
climate change, which can be applied to the long-run annual residential UPC forecast in
the IRP simulation model. This process starts with the following regression model:
[9A] 𝑈𝑃𝐶,= 𝛼+ 𝛼𝐻𝐷𝐷+ 𝛼𝐶𝐷𝐷+ 𝛼𝑇∗+ 𝛼𝐷 + 𝛼𝐷+
𝜖

Here HDDyAVA and CDDyAVA are the actual Avista adjusted degree days in year y; T* is a
linear trend starting with T*= 1 in 1997 (the beginning of the historical series); the
structural change dummies control for a change in data reporting after 1999 and the LEAP
gas program that ended in 2019;and εy is N(0, σ). None linear trends were also tried, by
the linear trend produced the best fit on the annual data. Using the estimated coefficients
(a), a forecast for UPC under climate change can be generated as follows:
[10A] 𝐹𝑈𝑃𝐶, = 𝑎+ 𝑎𝐻𝐷𝐷,+ 𝑛𝜇∆ + 𝑎𝐶𝐷𝐷,+ 𝑛𝜇∆ + 𝑎𝑇∗+
𝑛 𝑓𝑜𝑟 𝑛 = 0,… ,𝑁
Simplifying terms:
[11A] 𝐹𝑈𝑃𝐶, = 𝑎+ 𝑎𝐻𝐷𝐷,+ 𝑎𝐶𝐷𝐷,+ 𝑎(𝑇∗+ 𝑛) + (𝑎𝜇∆+
𝑎𝜇∆)𝑛

[12A] 𝐹𝑈𝑃𝐶, = 𝑎+ 𝑎𝐻𝐷𝐷,+ 𝑎𝐶𝐷𝐷, + 𝑎𝑇∗+ 𝑛 + 𝑏𝑛 𝑤ℎ𝑒𝑟𝑒 𝑏 ≡
(𝑎𝜇∆+ 𝑎𝜇∆)
Note that 𝑏 ≡ (𝑎𝜇∆+ 𝑎𝜇∆) is treated as the annual marginal impact of total
climate change on UPC. Using the times series questions [3A] and [4A], we have µΔHDD
= -9.6 and µΔHDD = 3.4. Combining these with the estimated values of a1 = 0.732 and a2 =
1.170 we have:

[13A] 𝑏 = 𝑎𝜇∆+ 𝑎𝜇∆= 0.732 ∙(−9.6)+ 1.170 ∙(3.4)= −3.049

This means the net impact of falling HDD and rising CDD is to reduce residential UPC
approximately 3 kWh a year, or a total cumulative impact b·N. Note that in the case of the
NPCC data, [x.x] becomes:

[14A] 𝑏 = 0.732 ∙(−38)+ 1.170 ∙(8)= −18.455
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1101 of 1105
Appendix K Page 4

In the context of the IRP simulation model, it is necessary to convert the annual load and
energy forecasts into a monthly number. Without climate change, this is straightforward
because it only requires extrapolating out the most recent 5-year forecast using the
forecasted long-run annual growth rates from the simulation model. This approach
essentially assumes the share of load by month in each year will not change significantly
over time, which is equivalent to assuming the most current 20-year moving average of
HDD and CDD is constant over the forecast horizon (see again Line A in Figure 1A).

However, with climate change, the share of load occurring each month will change
overtime. This means a method for estimating those future monthly load shares is
necessary to allocate the annual load values from the IRP simulation model. Since total
load can be trended over time, the method chosen here estimates a regression using the
first difference of month-to-month changes in total load and HDD and CDD, monthly
dummies (Dt,y), and an ARIMA error correction term to account for short-term
autocorrelation:
[15A] ∆𝐿,= 𝛽+ 𝛽∆𝐻𝐷𝐷,+ 𝛽∆𝐶𝐷𝐷,+ 𝜷𝟑,𝑺𝑫𝑫𝒕,𝒚+
𝐴𝑅𝐼𝑀𝐴𝜖,(𝑝,𝑑,𝑞)(𝑝,𝑑,𝑞)

Here ΔLt,y = Lt - Lt-1; ΔHDDt,yAVA = HDDtAVA - HDD t-1AVA; ΔCDDt,yAVA = CDDtAVA - CDD t-1AVA.
Note that as will be shown shortly, β0 reflects the growth in load that occurs each month
over the forecast horizon. If β0 > 0, then this reflects positive load growth; β0 = 0 means
no load growth; and β0 > 0.

For the purposes of forecasting future load shares, the ARIMA portion is ignored and the
forecasted change in load relies solely on the estimated coefficients (b). This is done
because simulations including and excluding error term corrections found little impact
after the first year:

[16A] 𝐹∆𝐿, = 𝑏+ 𝑏𝐹∆𝐻𝐷𝐷,, + 𝑏𝐹∆𝐶𝐷𝐷,,+ 𝒃𝟑,𝑺𝑫𝑫𝒕,𝒚𝒏 𝑓𝑜𝑟 𝑛 =
1, …, 𝑁

Given [16A] and forecast of HDD and CDD, a monthly load forecast can start with, L12,Yc,
the last actual value for December of the most recent full calendar year, and the forecast
would carry to year N. For simplicity, note that the forecast notation, F(·), has been
dropped:
𝐿,= 𝐿,+ ∆𝐿,
𝐿,= 𝐿,+ ∆𝐿,
𝐿,= 𝐿,+ ∆𝐿,
⋮
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1102 of 1105
Appendix K Page 5
𝐿,= 𝐿,+ ∆𝐿,
𝐿,= 𝐿,+ ∆𝐿,
𝐿,= 𝐿,+ ∆𝐿,
⋮
𝐿,= 𝐿,+ ∆𝐿,
𝐿,= 𝐿,+ ∆𝐿,
⋮
𝐿,= 𝐿,+ ∆𝐿,
𝐿,= 𝐿,+ ∆𝐿,

This process generates a series of total load values for each calendar year, n, over the
forecast horizon.

[17A] 𝐿= 𝐿,

Therefore, for each year, n, the forecasted load share over that year can be calculated
as:

[18A] ,= 𝜆,= 1

The monthly load shares can be applied to the annual forecast values in the simulation
model convert the annual forecasts to monthly values. However, prior to this allocation, it
may be required to manually adjust the estimated constant, b0, so that the average annual
load growth rate associated with [16A] matches the average annual growth rate from the
IRP simulation model. That is, because [16A] is being estimated from historical data, b0
reflects historical non-weather related growth. This can be seen by re-arranging [17A] as
follows:
[19A] 𝐿= 𝐿,= 𝐿,()+ 𝐿,+ ∆𝐿, 𝑓𝑜𝑟 𝑛 = 1,…,𝑁
Substituting in the estimated regression [16A]:
[20A] 𝐿= 𝐿,()+ 𝐿,+ (𝑏+ 𝑏∆𝐻𝐷𝐷,,+
𝑏∆𝐶𝐷𝐷,,+ 𝒃𝟑,𝑺𝑫𝑫𝒕,𝒚)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1103 of 1105
Appendix K Page 6
[21A] 𝐿= 12𝑏+ 𝐿,()+ 𝐿,+ ( 𝑏∆𝐻𝐷𝐷,,+
𝑏∆𝐶𝐷𝐷,,+ 𝒃𝟑,𝑺𝑫𝑫𝒕,𝒚)

[21A] shows that for any calendar year, non-weather-related load accumulates by 12b0.
Accounting for the accumulation over all N periods:

[22A] 𝐿,= 𝐿,+ ∆𝐿,+ ∆𝐿,+ ∆𝐿,…+ ∆𝐿,()+
∆𝐿,

[23A] 𝐿,= 𝐿,+ (∑∆𝐿)

[24A] 𝐿,= 𝐿,+𝑏+ 𝑏∆𝐻𝐷𝐷,+ 𝑏∆𝐶𝐷𝐷,+ 𝒃𝟑,𝑺𝑫𝑫𝒕,𝒚

[25A] 𝐿,= 𝐿,+ 𝑁12𝑏+𝑏∆𝐻𝐷𝐷,+ 𝑏∆𝐶𝐷𝐷,+ 𝒃𝟑,𝑺𝑫𝑫𝒕,𝒚

Non-weather related load accumulation over all N periods is N12b0.
To integrate climate change into the peak load model, note that any 20-year moving
average can be used to calculate the implied average temperature associated with a
given month, t; note that C is the cut-off for CDD and HDD, which Avista sets at 65
degrees, and D is the number of days in month t:
[26A] 𝐶𝐷𝐷,,=
,
=
,,
=
,,∙
=
∙∙,,
= −𝐷 ∙ 𝐶 + 𝐷
,,
= −𝐷 ∙ 𝐶 + 𝐷𝑇,,⇒ 𝑇,,=∙,,

[27A] 𝐻𝐷𝐷,,=
,
=
,,=
∙,,=
∙∙,,= 𝐷 ∙ 𝐶 − 𝐷,,= 𝐷 ∙ 𝐶 − 𝐷 ∙ 𝑇,,⇒ 𝑇,,=∙,,

Given forecasted values for the 20-year moving average of HDD and CDD (equations
[5A] and [6A]), the formulas above are used to calculate the implied 20-year moving
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1104 of 1105
Appendix K Page 7
average of average temperature forecasted for month t. The average annual change in
this temperature can be applied to calculate the expected change in average summer
and winter peak temperatures for integrating climate change into the peak load forecast.
Note that the growing (summer) or falling (winter) temperatures with act to accelerate
growth (in the case of summer) or decelerate growth (in the case of winter), in addition to
any impact associated with assumed economic growth. Thus:
[28A] ∆𝑇,=,,,,
() 𝑓𝑜𝑟 𝑒𝑖𝑡ℎ𝑒𝑟 𝐶𝐷𝐷 𝑜𝑟 𝐻𝐷𝐷 𝑓𝑜𝑟 𝑚𝑜𝑛𝑡ℎ 𝑡

[29A] 𝐹(𝐴,,) =
,,
+ 𝑛 ∙ ∆𝑇, 𝑓𝑜𝑟 𝑛 = 1,…,𝑁 𝑦𝑒𝑎𝑟𝑠
[30A] 𝐹(𝐴,,) =,,+ 𝑛 ∙ ∆𝑇, 𝑓𝑜𝑟 𝑛 = 1,…,𝑁 𝑦𝑒𝑎𝑟𝑠
From each series At,y, MAX is based on maximum daily average temperature and MIN is
based on minimum average daily temperatures. The first expression on the right of the
equals sign is the current 20-year historic average of MAX and MIN temperatures. The
second expression is the trending factor applied to the 20-year average. These trended
averages can then be converted back into CDD and HDD to be used in the peak-load
forecast model. These provide a trended values of CDD and HDD associated with peak
load.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 1a, Page 1105 of 1105
CONFIDENTIAL subject to Attorney’s Certificate of Confidentiality
Entire Document is CONFIDENTIAL
Avista Utilities Energy Resources Risk Policy
Pages 1 through 38
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01
S.Kinney, Avista
Schedule 2(R), Page 1 of 1
2021 Natural Gas
Integrated Resource Plan
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 1 of 184
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Schedule 3, Page 2 of 184
Safe Harbor Statement
This document contains forward-looking statements. Such statements are subject to a
variety of risks, uncertainties and other factors, most of which are beyond the Company’s
control, and many of which could have a significant impact on the Company’s operations,
results of operations and financial condition, and could cause actual results to differ
materially from those anticipated.
For a further discussion of these factors and other important factors, please refer to the
Company’s reports filed with the Securities and Exchange Commission. The forward-
looking statements contained in this document speak only as of the date hereof. The
Company undertakes no obligation to update any forward-looking statement or
statements to reflect events or circumstances that occur after the date on which such
statement is made or to reflect the occurrence of unanticipated events. New risks,
uncertainties and other factors emerge from time to time, and it is not possible for
management to predict all of such factors, nor can it assess the impact of each such factor
on the Company’s business or the extent to which any such factor, or combination of
factors, may cause actual results to differ materially from those contained in any forward-
looking statement.
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Schedule 3, Page 3 of 184
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Production

Primary Natural Gas IRP Team

Name Title Contribution
Tom Pardee Natural Gas Planning Manager IRP Core Team
Michael Brutocao Natural Gas Analyst IRP Core Team
Terrence Browne Sr Gas Planning Engr Gas Engineering
Grant Forsyth Chief Economist Load Forecast
Ryan Finesilver Mgr. of Energy Efficiency, Planning & Analysis Energy Efficiency

Natural Gas IRP Contributors
Name Title Contribution
Jody Morehouse Director of Gas Supply Gas Supply
John Lyons Sr. Policy Analyst Power Supply
Shawn Bonfield Sr. Manager of Regulatory Policy Regulatory
James Gall IRP Manager Power Supply
Justin Dorr Natural Gas Resource Manager Gas Supply
Michael Whitby Mgr Renewable Natural Gas Prog Gas Supply
Annie Gannon Communications Manager Communications

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TABLE OF CONTENTS
0 Executive Summary…………………………………………………1
1 Introduction………………………………………………………….14
2 Demand Forecasts………………………………………………....24
3 Demand Side Resources………………………………………….44
4 Supply Side Resources……………………………………………68
5 Carbon Reduction………………………………………………….96
6 Integrated Resource Portfolio……………………………………111
7 Alternate Scenarios, Portfolios, and Stochastic Analysis……..138
8 Distribution Planning………………………………………………157
9 Action Plan………………………………………………………….167
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Executive Summary
Avista’s 2021 Natural Gas Integrated Resource Plan (IRP) identifies a strategic natural
gas resource portfolio to meet customer demand requirements over the next 20 years.
Price volatility, or uncertainty, in the Pacific Northwest region, due to fully subscribed
transportation has increased in recent years. As weather events throughout the United
States have continued to rise, the risk to energy providers, utilities and consumers to
these unknown events are also on the rise. Some recent examples include freezing
temperatures in Texas and wildfire risk in California. Both events created the loss of a
supply source and potentially dangerous circumstances for its customers. This IRP’s
primary focus is to meet our customers’ needs under peak weather conditions, while
evaluating our customer needs under normal or average conditions. The formal exercise
of bringing together customer demand forecasts with comprehensive analyses of
resource options, including supply-side resources and demand-side measures, is
valuable to Avista, its customers, regulatory agencies, and other stakeholders for long-
range planning.

Benefits of Natural Gas

For Customers: Natural gas is affordable, resilient, and reliable.
For Society: Natural gas is an abundant energy resource produced in North America,
which helps lessen our dependency on foreign oil.
For Innovation: Natural gas can play a supporting role in expanding the use of
renewable energy sources.
For Environment: Natural gas is the cleanest burning fossil fuel, so it helps reduce smog
and greenhouse gas emissions.
For Economy: Natural gas provides nearly a fourth of North America's energy today.

IRP Process and Stakeholder Involvement
The IRP is a coordinated effort by several Avista departments with input from our
Technical Advisory Committee (TAC), which includes Commission Staff, peer utilities,
customers, and other stakeholders. The TAC is a vital component of our IRP process that
provides a forum for discussing multiple perspectives, identifies issues and risks, and
improves analytical planning methods. TAC topics include natural gas demand forecasts,
price forecasts, demand-side management (DSM), supply-side resources, modeling
tools, distribution planning, and policy issues. The IRP process produces a resource
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portfolio designed to serve our customers’ natural gas needs while balancing cost and
risk.

Planning Environment
A long-term resource plan addresses the uncertainties inherent in any planning exercise.
Natural gas is an abundant North American resource with expectations for ample supplies
for many decades because of continuing technological advancements in extraction. The
use of natural gas in liquefied natural gas (LNG) exports, power generation and exports
to Mexico will continue to add demand for natural gas. In addition to fossil fuel natural
gas, renewable natural gas and hydrogen are considered vital toward any carbon
reduction goal, but currently not as readily available. All future scenarios carry risk based
on unknown prices and expected resources. To account for risk associated with these
uncertainties, we model various sensitivities and scenarios to account for the risks in
supply and demand.

Demand Forecasts
Avista defines eleven distinct demand areas in this IRP structured around the pipeline
transportation and storage resources that serve them. Demand areas include Avista’s
service territories (Washington; Idaho; Medford/Roseburg, Oregon; Klamath Falls,
Oregon and La Grande, Oregon) and then disaggregated by the pipelines serving them.
The Washington, Medford and Idaho service territories include areas served only by
Northwest Pipeline (NWP), only by Gas Transmission Northwest (GTN), and by both
pipelines.
Weather, customer growth and use-per-customer are the most significant demand
influencing factors. Other demand influencing factors include population, employment,
age and income demographics, construction levels, conservation technology, new uses,
and use-per-customer trends.
Customers may adjust consumption in response to price, so Avista analyzed factors that
could influence natural gas prices and demand through price elasticity. These factors
include:
• Supply: shale gas, industrial use, and exports to Mexico and of LNG.
• Infrastructure: regional pipeline projects, national pipeline projects, and
storage.
• Regulatory: subsidies, market transparency/speculation, and carbon
regulation.
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• Other: drilling innovations, thermal generation and energy correlations (i.e.
oil/gas, coal/gas, and liquids/gas).
Avista developed a historical-based reference case and conducted sensitivity analysis on
key demand drivers by varying assumptions to understand how demand changes. Using
this information, and incorporating input from the TAC, Avista created alternate demand
scenarios for detailed analysis. Table 1 summarizes these demand scenarios, which
represent a broad range of potential scenarios for planning purposes. The Average Case
represents Avista’s demand forecast for normal planning purposes. The Expected Case
is the most likely scenario for peak day planning purposes.
Table 1: Demand Scenarios
2021 IRP Demand Scenarios
Average Case
Expected Case
High Growth, Low Price
Low Growth, High Price
Carbon Reduction

The IRP process defines the methodology for the development of two primary types of
demand forecasts – annual average daily and peak day. The annual average daily
demand forecast is useful for preparing revenue budgets, developing natural gas
procurement plans, and preparing purchased gas adjustment filings. Forecasts of peak
day demand are critical for determining the adequacy of existing resources or the timing
for new resource acquisitions to meet our customers’ natural gas needs in extreme
weather conditions. Table 2 shows the Average and Expected Case demand forecasts:
Table 2: Annual Average and Peak Day Demand Cases (Dth/day)
Year Annual Average
Daily Demand
Peak Day
Demand
Non-coincidental Peak
Day Demand
2021 95,126 363,586 349,210
2040 102,054 407,216 388,615

Annual Average Daily Demand
Expected average day, system-wide core demand increases from an average of 95,126
dekatherms per day (Dth/day) in 2021 to 102,054 Dth/day in 2040. These numbers are
net of projected conservation savings from DSM programs. Appendix 3.1 shows gross
demand, conservation savings and net demand.
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Peak Day Demand
The peak day demand for the Washington, Idaho and La Grande service territories is
modeled on and around February 28th of each year. For the southwestern Oregon service
territories (Medford, Roseburg, Klamath Falls), the model assumes this event on and
around December 20th of each year. Expected coincidental peak day, or the sum of
demand from each territories modeled peak, the system-wide core demand increases
from a peak of 363,586 Dth/day in 2021 to 407,216 Dth/day in 2040. Forecasted non-
coincidental peak day demand, or the sum of demand from the highest single day
including all forecasted territories, peaks at 349,210 Dth/day in 2021 and increases to
388,615 Dth/day in 2040. This is also net of projected conservation savings from DSM
programs.
Figure 1 shows forecasted average daily demand for the five demand scenarios modeled
over the IRP planning horizon.
Figure 1: Average Daily Demand (Net of DSM Savings)
Figure 2 shows forecasted system-wide peak day demand for the five demand scenarios
modeled over the IRP planning horizon.

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Figure 2: Peak Day Demand Scenarios (Net of DSM Savings)
Natural Gas Price Forecasts
Natural gas prices are a fundamental component of integrated resource planning as the
commodity price is a significant element to the total cost of a resource option. Price
forecasts affect the avoided cost threshold for determining cost-effectiveness of
conservation measures. The price of natural gas also influences the consumption of
natural gas by customers. A price elasticity adjustment to use-per-customer reflects
customer responses to changing natural gas prices.
Avista expects carbon legislation at the state level through a cap and reduce (Oregon) or
social cost of carbon tax mechanism (Washington). Current IRP price forecasts include a
considerably higher carbon adder in Oregon and Washington, but no carbon cost in
Idaho. Avista analyzed three carbon sensitivities and their impact on demand forecasts
to address the uncertainty about carbon legislation. These sensitivities were applied to all
jurisdictions.
Avista combined forward prices with three fundamental price forecasts including a futures
pricing strip in the near term to develop an expected price strip at the Henry Hub. A set
of high and low price strips were developed based on the 95th and 25th percentile results
of 1,000 simulated prices. These three price curves represent a reasonable range of
pricing possibilities for this IRP analysis. The array of prices provides necessary variation
for addressing uncertainty of future prices. Figure 3 depicts the price forecasts used in
this IRP.

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Figure 3: Low/Medium/High Henry Hub Forecasts (Nominal $/Dth)
Historical statistical analysis shows a long run consumption response to price changes.
In order to model consumption response to these price curves, Avista utilized an expected
elasticity response factor of -0.081 for every 10% of price movement, as found in our
Medford/Roseburg service territory, and applied it under various scenarios and
sensitivities. As this price response continues to have a near muted response, Avista will
look for additional studies and methodologies to account for elasticity in future resource
plans where applicable.

Existing and Potential Resources
Avista has a diversified portfolio of natural gas supply resources, including access to and
contracts for the purchase of natural gas from several supply basins; owned and
contracted storage providing supply source flexibility; and firm capacity rights on six
pipelines. For potential resource additions, Avista considers incremental pipeline
transportation, renewable natural gas, storage options, hydrogen, distribution
enhancements, and various forms of LNG storage or service. Avista models aggregated
conservation potential that reduces demand if the conservation programs are cost-
effective over the planning horizon. The identification and incorporation of conservation
savings into the SENDOUT® model utilizes projected natural gas prices and the
estimated cost of alternative supply resources. The operational business planning
process starts with IRP identified savings and ultimately determines the near-term
program offerings. Avista actively promotes cost-effective DSM measures to our
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customers as one component of a comprehensive strategy to arrive at a mix of best
cost/risk adjusted resources.
Resource Needs
In both the High Growth and Low-price and the Carbon Reduction scenarios a resource
deficiency was observed. The High Growth and Low-Price scenario observed an energy
shortage, or it requires additional assets of any kind to supply more energy. The Carbon
Reduction scenario does not have an energy shortage, but rather a need for carbon
neutral or carbon reducing resources in order to reduce the carbon intensity of its supply
stream. Avista is not resource deficient within the Expected Case for the 20-year planning
horizon. As further information on goals and legislation come into focus, Avista will
integrate these guideposts into our Expected Case.
Figures 4 through 7 illustrate Avista’s peak day demand by service territory for both the
current and prior IRP. These charts compare existing peak day resources to expected
peak day demand by year and show the timing and extent of resource deficiencies, if any,
for the Expected Case. Based on this information, Avista has time to carefully monitor,
plan and analyze potential resource additions as described in the Ongoing Activities
section of Chapter 9 – Action Plan. Any underutilized resources will be optimized to
mitigate the costs incurred by customers until the resource is required to meet demand.
This management of long and short term resources provides the flexibility to meet firm
customer demand in a reliable and cost-effective manner as described in Supply Side
Resources – Chapter 4.

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Figure 4: Expected Case – WA & ID Existing Resources vs. Peak Day Demand
(Net of DSM)

Figure 5: Expected Case – Medford/Roseburg Existing Resources vs. Peak Day
Demand (Net of DSM)

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Figure 6: Expected Case – Klamath Falls Existing Resources vs. Peak Day
Demand (Net of DSM)

Figure 7: Expected Case – La Grande Existing Resources vs. Peak Day Demand
(Net of DSM)

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Figure 8: Scenario Comparisons of First Year Peak Demand Not Met with Existing
Resources

A critical risk remains in the slope of forecasted demand growth, which although
increasing continues to be almost flat in Avista’s current projections. This outlook implies
that existing resources will be sufficient within the planning horizon to meet dem and.
However, if demand growth accelerates, the steeper demand curve could quickly
accelerate resource shortages by several years. Figure 9 conceptually illustrates this risk.
In this hypothetical example, a resource shortage does not occur until year eight in the
initial demand case. However, the shortage accelerates by five years under the revised
demand case to year three. This “flat demand risk” requires close monitoring of
accelerating demand, as well as careful evaluation of lead times to acquire the preferred
incremental resource.

2020 2025 2030 2035 2040
Low Growth & High Prices
Average Case
Carbon Reduction
High Growth & Low Prices
Expected Case
First Year Shortage vs. carbon reduction goalsFirst Year Shortage vs. Existing Resources
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Figure 9: Hypothetical Flat Demand Risk Example

Issues and Challenges
Even with the planning, analysis, and conclusions reached in this IRP, there is still
uncertainty requiring diligent monitoring of the following issues.

Demand Issues
Although the future customer growth trajectory in Avista’s service territory has slightly
decreased compared to the 2018 IRP, the need in considering a range of demand
scenarios provides insight into how quickly resource needs can change if demand varies
from the Expected Case.
With a robust supply forecast and continued low costs, there is increasing interest in using
natural gas. Avista does not anticipate traditional residential and commercial customers
will provide increased growth in demand. Power generation from natural gas is
increasingly being used to back up solar and wind technology as well as replacing retired
coal plants. In terms of North American demand, exports of LNG could consume 20 Bcf
per day by 2030 and more than 30 Bcf per day by 2040. Although smaller in size, Mexico
exports could increase from 5 Bcf per day in 2020 to over 8 Bcf per day in 2040. Most of
these emerging markets will not be core customers of the LDC, but could affect regional
natural gas infrastructure and natural gas pricing if an LNG export facility is built in the
area.
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Price Issues
Shale oil and gas drilling technology is adding an abundant amount of supply at low cost.
This is primarily due to increasingly efficient drilling technology and the rapid
advancement in understanding of drilling shale wells. In areas such as the eastern United
States, shale production is so prolific the entire flow of gas on the pipeline infrastructure
has changed and is now flowing out of the highest demand areas in the US. This supply
also flows into Canada and across the U.S. which benefits Northwest consumers as the
prices for Canadian gas have deep discounts as compared to the Henry Hub.

Action Plan
Avista’s 2021-2022 Action Plan outlines activities for study, development and preparation
for the 2023 IRP. The purpose of the Action Plan is to position Avista to provide the best
cost/risk resource portfolio and to support and improve IRP planning. The Action Plan
identifies needed supply and demand side resources and highlights key analytical needs
in the near term. It also highlights essential ongoing planning initiatives and natural gas
industry trends Avista will monitor as a part of its ongoing planning processes (Chapter 9
– Action Plan).
Key ongoing components of the Action Plan include:
1. Further model carbon reduction
2. Investigate new resource plan modeling software and integrate Avista’s system
into software to run in parallel with Sendout
3. Model all requirements as directed in Executive Order 20-04
4. Avista will ensure Energy Trust (ETO) has sufficient funding to acquire therm
savings of the amount identified and approved by the Energy Trust Board.
5. Explore the feasibility of using projected future weather conditions in its design day
methodology, rather than relying exclusively on historic data.
6. Regarding high pressure distribution or city gate station capital work, Avista does
not expect any supply side or distribution resource additions to be needed in our
Oregon territory for the next four years, based on current projections. However,
should conditions warrant that capital work is needed on a high-pressure
distribution line or city gate station in order to deliver safe and reliable services to
our customers, the Company is not precluded from doing such work. Examples of
these necessary capital investments include the following:
• Natural gas infrastructure investment not included as discrete projects in IRP
– Consistent with the preceding update, these could include system
investment to respond to mandates, safety needs, and/or maintenance
of system associated with reliability
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• Including, but not limited to Aldyl A replacement, capacity
reinforcements, cathodic protection, isolated steel replacement,
etc.
– Anticipated PHMSA guidance or rules related to 49 CFR Part §192 that
will likely require additional capital to comply
• Officials from both PHMSA and the AGA have indicated it is not
prudent for operators to wait for the federal rules to become final
before improving their systems to address these expected rules.
– Construction of gas infrastructure associated with growth
– Other special contract projects not known at the time the IRP was
published
• Other non-IRP investments common to all jurisdictions that are ongoing, for
example:
– Enterprise technology projects & programs
– Corporate facilities capital maintenance and improvements
Ongoing Activities
Meet regularly with Commission Staff to provide information on market activities and
significant changes in assumptions and/or status of Avista activities related to the IRP or
natural gas procurement practices.
Appropriate management of existing resources including optimizing underutilized
resources to help reduce costs to customers.

Conclusion
A slightly lower customer growth level combined with an updated peak weather planning
standard combine to create a lower overall peak day demand. Prices have a lower
levelized price as compared to the 2018 IRP creating a slightly reduced amount of DSM.
When combined, the need for additional supply side resources is pushed well into the
future. By managing these assets through releases and optimization, Avista can help
offset these costs while managing peak day demand need. A changing dynamic related
to carbon emissions will continue to evolve future planning environments and any need
for supply side resources. Regardless of policy, prices or demand, Avista will continue to
properly plan to continue delivering safe, reliable, and economic natural gas service to
our customers.

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1: Introduction
Avista is an investor-owned utility involved in the production, transmission and distribution
of natural gas and electricity, as well as other energy-related businesses. Avista, founded
in 1889 as Washington Water Power, has been providing reliable, efficient and
reasonably priced energy to customers for over 130 years.
Avista entered the natural gas business with the purchase of Spokane Natural Gas
Company in 1958. In 1970, it expanded into natural gas storage with Washington Natural
Gas (now Puget Sound Energy) and El Paso Natural Gas (its interest subsequently
purchased by NWP) to develop the Jackson Prairie natural gas underground storage
facility in Chehalis, Washington. In 1991, Avista added 63,000 customers with the
acquisition of CP National Corporation’s Oregon and California properties. Avista sold the
California properties and its 18,000 South Lake Tahoe customers to Southwest Gas in
2005. Figure 1.1 shows where Avista currently provides natural gas service to
approximately 361,000 customers in eastern Washington, northern Idaho and several
communities in northeast and southwest Oregon. Figure 1.2 shows the number of firm
natural gas customers by state.
Figure 1.1: Avista’s Natural Gas Service Territory

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Figure 1.2: Avista’s Natural Gas Customer Counts

Avista’s natural gas operations covers 30,000 square miles in eastern Washington,
northern Idaho and portions of southern and eastern Oregon, with a population of 1.6
million. The company manages its natural gas operation through the North and South
operating divisions:
• The North Division includes Avista’s eastern Washington and northern Idaho
service area which is home to over 1,000,000 people. It includes urban areas,
farms, timberlands, and the Coeur d’Alene mining district. Spokane is the largest
metropolitan area with a regional population of approximately 523,000 followed
by the Lewiston, Idaho/Clarkston, Washington, and Coeur d’Alene, Idaho, areas.
The North Division has about 75 miles of natural gas transmission pipeline and
5,800 miles in the distribution system in Washington and 3,300 miles in Idaho.
The North Division receives natural gas at more than 40 points along interstate
pipelines for distribution to over 257,000 customers.
• The South Division serves four counties in southern Oregon and one county in
eastern Oregon. The combined population of these areas is over 514,000
residents. The South Division includes urban areas, farms and timberlands. The
Medford, Ashland and Grants Pass areas, located in Jackson and Josephine
Counties, is the largest single area served by Avista in this division with a regional
population of approximately 308,000. The South Division consists of about 15
miles of natural gas transmission main and 3,700 miles of distribution pipelines.
Avista receives natural gas at more than 20 points along interstate pipelines and
distributes it to more than 104,000 customers.
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Customers
Avista provides natural gas services to both core and transportation-only customer
classes. Core or retail customers purchase natural gas directly from Avista with delivery
to their home or business under a bundled rate. Core customers on firm rate schedules
are entitled to receive any volume of natural gas they require. Some core customers are
on interruptible rate schedules. These customers pay a lower rate than firm customers
because their service can be interrupted. Interruptible customers are not considered in
peak day IRP planning.
Transportation-only customers purchase natural gas from third parties who deliver the
purchased gas to our distribution system. Avista delivers this natural gas to their business
charging a distribution rate only. Avista can interrupt the delivery service when following
the priority of service tariff. The long-term resource planning exercise excludes
transportation-only customers because they purchase their own natural gas and utilize
their own interstate pipeline transportation contracts. However, distribution planning
includes these customers.
Avista’s core or retail customers include residential, commercial and industrial categories.
Most of Avista’s customers are residential, followed by commercial and relatively few
industrial accounts (Figure 1.3).
Figure 1.3: Firm Customer Mix

56,354 7,038 14
6,794 943
3
77,804 9,164
89
13,889 2,189 2
155,069 14,980 130
15,192 1,787 6
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Res Com Ind
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The customer mix is found mostly in the residential and commercial accounts on an
annual volume basis (Figure 1.4). Volume consumed by core industrial customers is not
significant to the total, partly because most industrial customers in Avista’s service
territories are transportation-only customers.
Figure 1.4: 2019 Daily Demand by Area and Class
The seasonal nature of weather in the Pacific Northwest can drastically alter the amount
of energy demanded from the natural gas system (Figure 1.5). Industrial demand, which
is typically not weather sensitive, has very little seasonality. However, the La Grande
service territory has several industrially classified agricultural processing facilities that
produce a late summer seasonal demand spike.
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Figure 1.5: Total System Average Daily Load

Integrated Resource Planning
Avista’s IRP involves a comprehensive analytical process to ensure that core firm
customers receive long-term reliable natural gas service in extreme weather. The IRP
evaluates, identifies, and plans for the acquisition of an optimal combination of existing
and future resources using expected costs and associated risks to meet average daily
and peak-day demand delivery requirements over a 20-year planning horizon.
Purpose of the IRP
Avista’s 2021 Natural Gas IRP:
• Provides a comprehensive long-range planning tool;
• Fully integrates forecasted requirements with existing and potential resources;
• Determines the most cost-effective, risk-adjusted means for meeting future
demand requirements; and
• Meets Washington, Idaho and Oregon regulations, commission orders, and other
applicable guidelines.
Avista’s IRP Process
The natural gas IRP process considers:
• Customer growth and usage;
• Weather planning standard;
-
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• Conservation opportunities;
• Existing and potential supply-side resource options;
• Current and potential legislation/regulation;
• Risk; and
• Least cost mix of supply and conservation.
Public Participation
Avista’s TAC members play a key role and have a significant impact in developing the
IRP. TAC members included Commission Staff, peer utilities, government agencies, and
other interested parties. TAC members provide input on modeling, planning assumptions,
and the general direction of the planning process.
Avista sponsored four TAC meetings to facilitate stakeholder involvement in the 2021
IRP. The first meeting convened on June 17, 2020 and the last meeting occurred on
November 18, 2020. All meetings were held virtually, via web meetings, due to the
restrictions and guidelines around the COVID-19 pandemic. Each meeting included a
broad spectrum of stakeholders. The meetings focused on specific planning topics,
reviewing the progress of planning activities, and soliciting input on IRP development and
results. TAC members received a draft of this IRP on January 4, 2021 for their review.
Avista appreciates the time and effort TAC members contributed to the IRP process; they
provided valuable input through their participation in the TAC process. A list of these
organizations can be found below (Table 1.1).
Table 1.1: TAC Member Participation
Cascade Natural Gas Northwest Energy Coalition Oregon Public Utility
Commission
Fortis Northwest Natural Gas Idaho Conservation League
Idaho Public Utilities
Commission
Biomethane, LLC

Washington State Office of
the Attorney General
Northwest Gas
Association
Washington Utilities and
Transportation Commission
Citizens Utility Board of
Oregon

Washington State
Department of
Commerce
Northwest Power and
Conservation Council Energy Trust of Oregon
Intermountain Gas
Company
Alliance of Western Energy
Consumers
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 28 of 184
Preparation of the IRP is a coordinated endeavor by several departments within Avista
with involvement and guidance from management. We are grateful for their efforts and
contributions.
Regulatory Requirements
Avista submits a natural gas IRP to the public utility commissions in Idaho, Oregon and
Washington every two years as required by state regulation. There is a statutory
obligation to provide reliable natural gas service to customers at rates, terms and
conditions that are fair, just, reasonable and sufficient. Avista regards the IRP as a means
for identifying methodologies and processes for the evaluation of potential resource
options and as a process to establish an Action Plan for resource decisions. Ongoing
investigation, analysis and research may cause Avista to determine that alternative
resources are more cost effective than resources reviewed and selected in this IRP.
Avista will continue to review and refine our understanding of resource options and will
act to secure these risk-adjusted, least-cost options when appropriate.
Planning Model
Consistent with prior IRPs, Avista used the SENDOUT® planning model to perform
comprehensive natural gas supply planning and analysis for this IRP. SENDOUT® is a
linear programming-based model that is widely used to solve natural gas supply, storage
and transportation optimization problems. This model uses present value revenue
requirement (PVRR) methodology to perform least-cost optimization based on daily,
monthly, seasonal and annual assumptions related to the following:
•Customer growth and customer natural gas usage to form demand forecasts;
•Existing and potential transportation and storage options and associated costs;
•Existing and potential natural gas supply availability and pricing;
•Revenue requirements on all new asset additions;
•Weather assumptions; and
•Conservation.
Avista incorporated stochastic modeling by utilizing a SENDOUT® module to incorporate
weather and price uncertainty. Some examples of the types of stochastic analysis
provided include:
•Price and weather probability distributions;
•Probability distributions of costs (i.e. system costs, storage costs, commodity
costs); and
•Resource mix (optimally sizing a contract or asset level of competing resources).
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 29 of 184
These computer-based planning tools were used to develop the 20-year best cost/risk
resource portfolio plan to serve customers.

Planning Environment
Even though Avista publishes an IRP every two years, the process is ongoing with new
information and industry related developments. In normal circumstances, the process can
become complex as underlying assumptions evolve, impacting previously completed
analyses. Widespread agreement on the availability of shale gas and the ability to
produce it at lower prices has increased interest in the use of natural gas for LNG and
Mexico exports as well as industrial uses. One of the most prominent risks in the IRP
involves policies meant to decrease the use of natural gas as outlined in Chapter 5-
Carbon Reduction. However, there is uncertainty about the timing and size of those policy
decisions.

IRP Planning Strategy
Planning for an uncertain future requires robust analysis encompassing a wide range of
possibilities. Avista has determined that the planning approach needs to:
• Recognize historical trends may be fundamentally altered;
• Critically review all modeling assumptions;
• Stress test assumptions via sensitivity analysis;
• Pursue a spectrum of scenarios;
• Develop a flexible analytical framework to accommodate changes; and
• Maintain a long-term perspective.
With these objectives in mind, Avista developed a strategy encompassing all required
planning criteria. This produced an IRP that effectively analyzes risks and resource
options, which sufficiently ensures customers will receive safe and reliable energy
delivery services with the best-risk, lease-cost, long-term solutions. The following chart
summarizes significant changes from the 2018 IRP (Table 1.2).

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 30 of 184
Table 1.2: Summary of Changes from the 2018 IRP
Chapter Issue 2021 Natural Gas IRP 2018 Natural Gas IRP
Demand
Expected
Customer
Growth
Expected Case – system
wide – growth is slightly
lower at 1.0%.
Expected Case – system
wide – growth at 1.2%.
Weather
Planning
Standard
99% probability of a
temperature occurring
based on the coldest
temperature each year
for the past 30 years
Coldest on record
DSM CPA
potential
A lower price curve and
slightly less conservation
potential

Cumulative Savings over
20 years:
ID: 21.4 Million Therms
OR: 14.8Million Therms
WA: 37.7 Million Therms
Cumulative Savings over
20 years:
ID: 21.1 Million Therms
OR: 17.2 Million Therms
WA: 41.4 Million Therms
Environmental
Issues
Carbon
Dioxide
Emission
(Carbon)
ID: No federal or State
initiatives ($0)
OR: Cap and Reduce
($15.83 – $97.90)
WA – Social Cost of
Carbon @ 2.5% discount
rate
($79.86 - $158.06)

*Prices are in nominal
dollars per MTCO2e
ID: No federal or State
initiatives ($0)
OR: HB 4001 & SB 1507
($17.86 – $51.58)
WA – SSB 6203 ($10 -
$30)

*Prices are in nominal
dollars per MTCO2e
Prices Price Curve
A lower price curve at
$3.73 levelized cost in
real 2019 US $
A levelized price at the
Henry Hub of $3.99 in
2017 real US $
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 31 of 184
Supply Side
Resources
Supply Side
Scenarios
There are two cases
where resource
deficiencies occur, the
High Growth/Low Price
scenario and the Carbon
Reduction scenario. The
High Growth/Low Price
scenario is solved by
adding RNG landfill
within the city gate. The
Carbon Reduction
scenario is looking to
reduce emissions and
Dairy RNG provides the
greatest amount of
carbon intensity/carbon
capture of RNG sources.
The only case that
identifies a resource
deficiency is the High
Growth/Low Price
scenario. Avista solved
this case by using existing
resources plus added
contracted capacity on
GTN. Landfill RNG is also
selected as a resource in
Idaho. Also selected is
the upsized compressor
on the Medford lateral.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 32 of 184
2: Demand Forecasts
Overview
The integrated resource planning process begins with the development of forecasted
demand. Understanding and analyzing key demand drivers and their potential impact on
forecasts is vital to the planning process. Utilization of historical data provides a reliable
baseline; however, forecasting will always have uncertainties regardless of methodology
and data integrity. This IRP mitigates the uncertainty by considering a range of scenarios
to evaluate and prepare for a broad spectrum of outcomes.
Demand Areas
Avista defined eleven demand areas, structured around the pipeline transportation
resources ability to serve them, within the SENDOUT® model (Table 2.1). These demand
areas are aggregated into five service territories and further summarized as North or
South divisions for presentation throughout this IRP.
Table 2.1: Geographic Demand Classifications
Demand Area Service Territory Division
Washington NWP Spokane North
Washington GTN Spokane North
Washington Both Spokane North
Idaho NWP Coeur D' Alene North
Idaho GTN Coeur D' Alene North
Idaho Both Coeur D' Alene North
Medford NWP Medford/Roseburg South
Medford GTN Medford/Roseburg South
Roseburg Medford/Roseburg South
Klamath Falls Klamath Falls South
La Grande La Grande South

Demand Forecast Methodology
Avista uses the IRP process to develop two types of demand forecasts – annual and peak
day. Annual average demand forecasts are useful for preparing revenue budgets,
developing natural gas procurement plans, and preparing purchased gas adjustment
filings. Peak day demand forecasts are critical for determining the adequacy of existing
resources or the timing for acquiring new resources to meet customers’ natural gas needs
in extreme weather conditions.
In general, if existing resources are sufficient to meet peak day demand, they will be
sufficient to meet annual average day demand. Developing annual average demand first
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 33 of 184
and evaluating it against existing resources is an important step in understanding the
performance of the portfolio under normal circumstances. It also facilitates
synchronization of modeling processes and assumptions for planning purposes.
Peak weather analysis aids in assessing resource adequacy and any differences in
resource utilization. For example, storage may be dispatched differently under peak
weather scenarios.
Demand Modeling Equation
Developing daily demand forecasts is essential because natural gas demand can vary
widely from day-to-day, especially in winter months when heating demand is at its highest .
In its most basic form, natural gas demand is a function of customer base usage (non-
weather sensitive usage) plus customer weather sensitive usage. Basic demand takes
the formula in Table 2.2:
Table 2.2: Basic Demand Formula
# of customers x daily base usage / customer
+
# of customers x daily weather sensitive usage / customer
SENDOUT® requires inputs as expressed in the Table 2.3 format to compute daily
demand in dekatherms.
Table 2.3: SENDOUT® Demand Formula
# of customers x daily Dth base usage / customer
+
# of customers x daily Dth weather sensitive usage / customer x # of daily degree days
Customer Forecasts
Avista’s customer base includes firm residential, commercial and industrial categories.
For each of the customer categories, Avista develops customer forecasts incorporating
national economic forecasts and then drilling down into regional economies. U.S. GDP
growth, national and regional employment growth, and regional population growth
expectations are key drivers in regional economic forecasts and are useful in estimating
the number of natural gas customers. A detailed description of the customer forecast is
found in Appendix 2.1 – Economic Outlook and Customer Count Forecast. Avista
combines this data with local knowledge about sub-regional construction activity, age and
other demographic trends, and historical data to develop the 20-year customer forecasts.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 34 of 184
300,000
350,000
400,000
450,000
500,000
550,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
SYSTEMCUS.syf Base SYSTEMCUS.syf High SYSTEMCUS.syf Low
Several Avista departments’ use these forecasts including Finance, Accounting, Rates,
and Gas Supply. The natural gas distribution engineering group utilizes the forecast data
for system optimization and planning purposes (see discussion in Chapter 8 – Distribution
Planning).
Forecasting customer growth is an inexact science, so it is important to consider different
forecasts. Two alternative growth forecasts were developed for this IRP. Avista developed
High and Low Growth forecasts to provide potential paths and test resource adequacy.
Appendix 2.1 contains a description of how these alternatives were developed.
Figure 2.1 shows the three customer growth forecasts. The expected case customer
counts are lower than the last IRP. This has impacted forecasted demand from both the
average and peak day perspective. Detailed customer count data by region and class for
all three scenarios is in Appendix. 2.2 – Customer Forecasts by Region. In comparison
to Avista’s 2018 IRP, the base forecast for customer growth decreases by nearly 1,400
new customers.
Figure 2.1: Customer Growth Scenarios

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 35 of 184
Use-per-Customer Forecast
The goal for a use-per-customer forecast is to develop base and weather sensitive
demand coefficients that can be combined and applied to heating degree day (HDD)
weather parameters to reflect average use-per-customer. This produces a reliable
forecast because of the high correlation between usage and temperature as depicted in
the example scatter plot in Figure 2.2.
Figure 2.2: Example Demand vs. Temperature – 2019

The first step in developing demand coefficients was gathering daily historical gas flow
data for Avista city gates. The use of city gate data over revenue data is due to the tight
correlation between weather and demand. The revenue system does not capture data
daily and, therefore, makes a statistical analysis with tight correlations on a daily basis
virtually impossible. Avista reconciles city gate flow data to revenue data to ensure that
total demand is properly captured.
The historical city gate data was gathered, sorted by service territory/temperature zone,
and then by month. As in the last IRP, Avista used three years of historical data to derive
the use-per-customer coefficients, but also considered varying the number of years of
historical data as sensitivities. When comparing five years of historical use-per-customer
to three years of data, the five-year data had slightly higher use-per-customer, which may
overstate use as efficiency and use-per-customer-per-HDD have been relatively stable in
recent history. The two-year use-per-customer was much more pronounced for demand,
likely based on a shorter timeframe for weather to impact the overall use-per-customer.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 36 of 184
The three-year coefficient most closely aligns with economic expectations and use within
Avista’s territories in the short-term forecast. Figure 2.3 illustrates the annual demand
differences between the three and five-year use-per-customer with normal and peak
weather conditions.
You can see the three year and 5-year coefficients are very close, with the two-year
coefficient clearly higher.
Figure 2.3: Annual Demand – Demand Sensitivities 2-Year, 3-Year and 5-Year Use-
per-Customer
The base usage calculation used three years of July and August data to derive
coefficients. Average usage in these months divided by the average number of customers
provides the base usage coefficient input into SENDOUT®. This calculation is done for
each area and customer class based on customer billing data demand ratios.
To derive weather sensitive demand coefficients for each monthly data subset, Avista
removed base demand from the total and plotted usage by HDD in a scatter plot chart to
verify correlation visually. The process included the application of a linear regression to
the data by month to capture the linear relationship of usage to HDD. The slopes of the
resulting lines are the monthly weather sensitive demand coefficients input into
SENDOUT®. Again, this calculation is done by area and by customer class using
allocations based on customer billing data demand ratios.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 37 of 184
Weather Forecast
The last input in the demand modeling equation is weather. The most current 20 years of
daily weather data (minimums and maximums) from the National Oceanic Atmospheric
Administration (NOAA) is used to compute an average for each day; this 20-year daily
average is used as a basis for the normal weather forecast. NOAA data is obtained from
five weather stations, corresponding to the areas where Avista provides natural gas
services (four in Oregon and one for Washington and Idaho), where this same 20-year
daily average weather computation is completed for all five areas. The HDD weather
patterns between the Oregon areas are uncorrelated, while the HDD weather patterns
amongst eastern Washington and northern Idaho portions of the service area are
correlated. Thus, Spokane Airport weather data is used for all Washington and Idaho
demand areas.
The NOAA 20-year average weather serves as the base weather forecast to prepare the
annual average demand forecast. The peak day demand forecast includes adjustments
to average weather to reflect a five-day cold weather event. The weather history for the
Avista territories modeled within this IRP goes back 70 years and contains minimum,
maximum and average weather data. The program utilizes the historic weather data
patterns to simulate realistic weather data algorithms when running stochastic
simulations.
The weather planning standard is an important piece of system planning for resources in
an IRP. In prior IRP’s a coldest on record approach was considered the planning
standard. With the complexities of changing weather and maintaining a reliable and
affordable system, finding a statistical methodology to weigh weather risk and cost risk
led to the development of a new weather planning standard methodology. The expected
weather planning standard will utilize a coldest average temperature each year for the
past thirty years, by planning area, and combine these temperatures with a 99%
probability of a weather occurrence. As shown in Figure 2.4. the coldest on record
temperature in Washington and Idaho has remained static, ignoring any weather trends.
With the updated methodology the 99% will adjust with changing trends in climate. This
will ensure capital is not being invested where an event is statistically unlikely to occur.
In the planning areas of La Grande and Klamath Falls, OR this peak weather standard
has become colder due to the large amount of peak or near peak events in the recent 30-
year weather history. This new standard will enhance Avista’s ability to plan for peak
weather events and paired with stochastic analysis will introduce more rigor and risk
analysis into the planning process and climate uncertainty.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 38 of 184
Figure 2.4: Spokane Weather Station – Weather Planning Standard Comparison

Utilizing a five-day cold weather event with the new weather planning standard will occur
by service territory while adjusting the two days on either side of the planning standard to
temperatures colder than average. For the Washington, Idaho and La Grande service
territories, the model assumes this event on and around February 28 each year. As
discussed in TAC 1, moving the peak day from February 15th to February 28th will allow
for availability of resources to serve customers in these late season cold weather events.
With supply side resources in the Pacific Northwest growing further constrained,
managing supply along with the ability to serve cold days is paramount. For the
southwestern Oregon service territories (Medford, Roseburg, Klamath Falls), the model
assumes this event on and around December 20 each year. The following section
provides a comparison of prior IRP planning standard vs. The updated methodology
(Table 2.4).

-12
-30
-20
-10
0
10
20
30
40
19
4
9
19
5
2
19
5
5
19
5
8
19
6
1
19
6
4
19
6
7
19
7
0
19
7
3
19
7
6
19
7
9
19
8
2
19
8
5
19
8
8
19
9
1
19
9
4
19
9
7
20
0
0
20
0
3
20
0
6
20
0
9
20
1
2
20
1
5
20
1
8
Coldest each year 99%Coldest on Record
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 39 of 184
Table 2.4: Weather Planning Standard
Area Coldest on Record
(Prior IRP’s)
99% Probability
Avg. Temp
La Grande -10 -11
Klamath Falls -7 -9
Medford 4 11
Roseburg 10 14
Spokane -17 -12

Warming trends are beginning to emerge in Roseburg and Medford, though the volatility
surrounding the peak is still present as seen in Figures 2.6 and 2.9. This indicates that
although temperatures, specifically in the Roseburg and Medford areas, are deviating
from the base years of 1950-1981 the peaking potential remains the same. The following
figures show this same analysis for all weather areas for the months of December,
January and February.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 40 of 184
Figure 2.5: Spokane

Figure 2.6: Medford

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 41 of 184
Figure 2.7: La Grande

Figure 2.8: Klamath Falls
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 42 of 184
Figure 2.9: Roseburg

Developing a Reference Case
To adjust for uncertainty, Avista developed a dynamic demand forecasting methodology
that is flexible to changing assumptions. To understand how various alternative
assumptions influence forecasted demand Avista needed a reference point for
comparative analysis. For this, Avista defined the reference case demand forecast shown
in Figure 2.10. This case is only a starting point to compare other cases.
Figure 2.10: Reference Case Assumptions
1. Customer Compound Annual Growth Rates
Area Residential Commercial Industrial
Idaho 1.4% 0.4% -1.0%
Oregon 0.7% 0.6% 0.0%
Washington 1.0% 0.4% -0.08%
System 1.0% 0.5% -0.8%

2. Use-Per-Customer Coefficients
Mostly Flat Across All Classes
3-year Average Use per Customer per HDD by Area/Class
3. Weather
20-year Normal – NOAA (2000-2019)
4. Elasticity
None
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 43 of 184
5. Conservation
None

Dynamic Demand Methodology
The dynamic demand planning strategy examines a range of potential outcomes. The
approach consists of:
• Identifying key demand drivers behind natural gas consumption;
• Performing sensitivity analysis on each demand driver;
• Combining demand drivers under various scenarios to develop alternative
potential outcomes for forecasted demand; and
• Matching demand scenarios with supply scenarios to identify unserved demand.
Figure 2.11 represents Avista’s methodology of starting with sensitivities, progressing to
portfolios, and ultimately selecting a preferred portfolio.
Figure 2.11: Sensitivities and Preferred Portfolio Selection

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 44 of 184
Sensitivity Analysis
In analyzing demand drivers, Avista grouped them into three categories based on:
• Demand Influencing Factors directly influencing the volume of natural gas
consumed by core customers.
• Price Influencing Factors indirectly influencing the volume of natural gas consumed
by core customers through a price elasticity response.
• Emissions Influencing Factors directly influencing the volume of gas and the price
elasticity response.
After identifying demand, price, and emissions influencing factors, Avista developed
sensitivities to focus on the analysis of a specific natural gas demand driver and its impact
on forecasted demand relative to the Reference Case when modifying the underlying
input assumptions.
Sensitivity assumptions reflect incremental adjustments not captured in the underlying
Reference Case forecast. Avista analyzed 33 demand sensitivities to determine the
results relative to the Reference Case. Table 2.5 lists these sensitivities. Detailed
information about these sensitivities is in Appendix 2.5 – Demand Forecast Sensitivities
and Scenarios Descriptions.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 45 of 184
Table 2.5: Demand Sensitivities

Figure 2.12 shows the annual demand from each of the sensitivities modeled for this IRP
with the associated legend colors in Table 2.5.
Figure 2.12: 2021 IRP Demand Sensitivities

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 46 of 184
Scenario Analysis
After testing the sensitivities, Avista grouped them into meaningful combinations of
demand drivers to develop demand forecasts representing scenarios. Table 2.6 identifies
the scenarios developed for this IRP. The Average Case represents the case used for
normal planning purposes, such as corporate budgeting, procurement planning, and
PGA/General Rate Cases. The Expected Case reflects the demand forecast Avista
believes is most likely given peak weather conditions. The High Growth/Low Price and
Low Growth/High Price cases represent a range of possibilities for customer growth and
future prices. The Carbon Reduction emissions scenario is intended to show a
progressive loss of demand in the areas of Oregon and Washington (Idaho is unaffected)
from policies targeting methane and carbon dioxide emissions to an estimated emissions
level. Each of these scenarios provides a “what if” analysis given the volatile nature of
key assumptions, including weather and price. Appendix 2.6 lists the specific assumptions
within the scenarios while Appendix 2.7 contains a detailed description of each scenario.
Table 2.6: Demand Scenarios
2021 IRP Demand Scenarios
Average Case
Expected Case
High Growth, Low Price
Low Growth, High Price
Carbon Reduction

Price Elasticity
The economic theory of price elasticity states that the quantity demanded for a good or
service will change with its price. Price elasticity is a numerical factor that identifies the
relationship of a customer’s consumption change in response to a price change. Typically,
the factor is a negative number as customers normally reduce their consumption in
response to higher prices or will increase their consumption in response to lower prices.
For example, a price elasticity factor of negative 0.15 for a good or service means a 10
percent price increase will prompt a 1.5 percent consumption decrease and a 10 percent
price decrease will prompt a 1.5 percent consumption increase. An example of price
elasticity is depicted in Figure 2.13:
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 47 of 184
Figure 2.13: Price Elasticity Example

Complex regulatory pricing mechanisms shield customers from price volatility, thereby
dampening price signals and affecting price elastic responses. For example, comfort level
billing averages a customer’s bills into equal payments throughout the year. This popular
program helps customers manage household budgets but does not send a timely price
signal. Additionally, natural gas cost adjustments, such as the Purchased Gas Adjustment
(PGA), annually adjusts the commodity cost which shields customers from daily gas price
volatility. These mechanisms do not completely remove price signals, but they can
significantly dampen the potential demand impact.
When considering a variety of studies on energy price elasticity, a range of potential
outcomes was identified, including the existence of positive price elastic adjustments to
demand. One study looking at the regional differences in price elasticity of demand for
energy found that the statistical significance of price becomes more uncertain as the
geographic area of measurement shrinks.1 This is particularly important given Avista’s
geographically diverse and relatively small service territories.
Avista acknowledges changing price levels can and do influence natural gas usage. This
IRP includes a price elasticity of demand factor of -0.081 for every 10% change in price
as measured in the Roseburg and Medford service territories. We assume the same
elasticity for all service areas in this study. When putting this elasticity into our model, it
allows the use-per-customer to vary as the natural gas price forecast changes.
Recent usage data indicates that even with declines in the retail rate for natural gas, long
run use-per-customer continues to decline. This likely includes a confluence of factors
1 Bernstein, M.A. and J. Griffin (2005). Regional Differences in Price-Elasticity of Demand for Energy, Rand
Corporation.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 48 of 184
including increased investments in energy DSM measures, building code improvements,
behavioral changes, and heightened focus of consumers’ household budgets.
Results
During 2021, the Average Case demand forecast indicates Avista will serve an average
of 366,157 core natural gas customers with 34,720,917 Dth of natural gas. By 2040,
Avista projects 442,863 core natural gas customers with an annual demand of over
37,351,708 Dth. In Washington/Idaho, the projected number of customers increases at
an average annual rate of 1.11 percent, with demand growing at a compounded average
annual rate of 0.33 percent. In Oregon, the projected number of customers increases at
an average annual rate of 0.75 percent, with demand growing 0.54 percent per year.
The Expected Case demand forecast indicates Avista will serve an average of 366,157
core natural gas customers with 35,440,513 Dth of natural gas in 2021. By 2040, Avista
projects 442,863 core natural gas customers with an annual demand of 37,987,712 Dth.
Figure 2.14 shows system forecasted demand for the demand scenarios on an average
daily basis for each year.2
Figure 2.14: Average Daily Demand – 2021 IRP Scenarios
Figure 2.15 shows system forecasted demand for the Expected, High and Low Demand
cases on a peak day basis for each year relative to the Average Case average daily winter
2 Appendix 2.1 shows gross demand, conservation savings and net demand.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 49 of 184
demand. Detailed data for all demand scenarios is in Appendix 2.8 – Demand Before and
After DSM.
Figure 2.15: February 28th – Peak Day – 2021 IRP Demand Scenarios
The IRP balances forecasted demand with existing and new supply alternatives. Since
new supply sources include conservation resources, which act as a demand reduction,
the demand forecasts prepared and described in this section include existing DSM
standards and normal market acceptance levels. The methodology for modeling DSM
initiatives is in Chapter 3 – Demand-Side Resources.
Alternative Forecasting Methodologies
There are many forecasting methods available and used throughout different industries.
Avista uses methods that enhance forecast accuracy, facilitate meaningful variance
analysis, and allows for modeling flexibility to incorporate different assumptions. Avista
believes the IRP statistical methodology to be sound and provides a robust range of
demand considerations while allowing for the analysis of different statistical inputs by
considering both qualitative and quantitative factors. These factors come from data,
surveys of market information, fundamental forecasts, and industry experts. Avista is
always open to new methods of forecasting natural gas demand and will continue to
assess which, if any, alternative methodologies to include in the dynamic demand
forecasting methodology.
Key Issues
Demand forecasting is a critical component of the IRP requiring careful evaluation of the
current methodology and use of scenario planning to understand how changes to the
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 50 of 184
underlying assumptions will affect the results. The evolution of demand forecasting over
recent years has been dramatic, causing a heightened focus on variance analysis and
trend monitoring. Current techniques have provided sound forecasts with appropriate
variance capabilities. However, Avista is mindful of the importance of the assumptions
driving current forecasts and understands that these can and will change over time.
Therefore, monitoring key assumptions driving the demand forecast is an ongoing effort
that will be shared with the TAC as they develop.
Flat Demand Risk
Forecasting customer usage is a complex process because of the number of underlying
assumptions and the relative uncertainty of future patterns of usage with a goal of
increasing forecast accuracy. There are many factors that can be incorporated into these
models, assessing which ones are significant and improving the accuracy are key. Avista
continues to evaluate economic and non-economic drivers to determine which factors
improve forecasting accuracy. The forecasting process will continue to review research
on climate change and the best way to incorporate the results of that research into the
forecasting process.
For the last few planning cycles, the TAC has discussed the changing slope of forecasted
demand. Growth has slowed due to a declining use-per-customer. Use-per-customer
seems to have stabilized, though it is still on a downward trajectory in some areas.
This reduced demand pushes the need for resources beyond the planning horizon, which
means no new investment in resources is necessary from an energy standpoint.
However, as discussed in Chapter 5 – Carbon Reduction, policy may change the resource
demand for fossil fuels based on carbon reduction goals where new carbon reducing
resources will be required to help meet these targets. Monitoring both growth and policy
changes is key to managing assets needed to serve customers energy demand in all
types of weather.
Emerging Natural Gas Demand
The shale gas revolution has fundamentally changed the long-term availability and price
of natural gas. An ever-growing demand for natural gas-fired generation to integrate
variable wind and solar resources along with an increasing demand from coal retirements
and fuel switching has developed over the last decade. This demand is expected to
increase due to the availability of natural gas combined with its lower carbon emissions.
Other areas of emerging demand include everything from methanol plants to food
processors, and interest in industrial processes using natural gas as a feedstock is
growing.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 51 of 184
Conclusion
Avista’s 20-year outlook for customer growth has decreased by nearly 1,400 customers,
as compared to Avista’s 2018 IRP. With the inclusion of energy efficiency, known as DSM,
measures going into new construction and purchased through Avista’s programs, homes
are becoming better equipped to keep the heat in. This in turn leads to a decreasing
amount of natural gas usage. Until a point is reached where maximum efficiency is found,
these trends will likely continue to decline in nature.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 52 of 184
3: Demand Side Resources
Overview
Avista is committed to offering natural gas Energy Efficiency portfolios to residential, low
income, commercial and industrial customer segments when it is feasible to do so in a
cost-effective manner as prescribed within each jurisdiction. Avista began offering natural
gas energy efficiency programs to its customers in 1995. Program delivery includes both
prescriptive and site-specific offerings. Prescriptive programs, or standard offerings,
provide cash incentives for standardized products such as the installation of qualifying
high-efficiency heating equipment. Delivering programs through a prescriptive approach
works in situations where uniform products or offerings are applicable for large groups of
homogeneous customers and primarily occur in programs for residential and small
commercial customers. Site specific is the most comprehensive offering of the
nonresidential segment. Avista’s Account Executives work with nonresidential customers
to aid in identifying energy efficiency opportunities. Customers receive technical
assistance in determining potential energy and cost savings as well as identifying and
estimating incentives for participation. Other delivery methods build off these approaches
and may include upstream buy downs of low-cost measures, free-to-customer direct
install programs, and coordination with regional entities for market transformation efforts.
Recently, programs with the highest impacts on natural gas energy savings include the
residential prescriptive HVAC measures, residential water heat measures, and
nonresidential prescriptive and site-specific HVAC.
Improved drilling and extraction techniques of natural gas has led to declines in natural
gas prices in recent years which has made offering cost-effective DSM programs
challenging using the Total Resource Cost Test (TRC) to test cost-effectiveness. Since
January 1, 2016, Washington and Idaho programs utilize the Utility Cost Test (UCT).
Effective January 1, 2017, all Oregon DSM programs, with the exception of low-income
conservation, are delivered and administered by the Energy Trust of Oregon (ETO)1.
Avista issued an RFP and chose Applied Energy Group (AEG) to perform an external
independent evaluation of Avista’s conservation potential in Idaho and Washington while
ETO continues to evaluate and manage DSM in Oregon. Included with these evaluations
was the technical, economic and achievable conservation potential for each state over a
20-year planning horizon (2021-2040).
1 As part of the settlement for the Avista 2015 Oregon General Rate case
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 53 of 184
The preliminary cost-effective conservation potential is determined by applying the stream
of annual natural gas avoided costs to the Avista-specific supply curve for conservation
resources. This quantity of conservation acquisition is then decremented from the load
which the utility must serve and the SENDOUT® model is rerun against the modified
(reduced) load requirements. The resulting avoided costs are compared to those obtained
from the previous iteration of SENDOUT® avoided costs. This process continues until the
differential between the avoided cost streams of the most recent and the immediately
previous iteration becomes immaterial. The resulting avoided costs were provided to AEG
and ETO to use in selecting cost-effective potential within Avista’s service territories.
Applied Energy Group (AEG): Idaho and Washington - CPA
Avista Early in 2020, Avista Utilities (Avista) contracted with Applied Energy Group (AEG)
to conduct this Conservation Potential Assessment (CPA) in support of their conservation
and resource planning activities. This report documents this effort and provides estimates
of the potential reductions in annual energy usage for natural gas customers in Avista’s
Washington and Idaho service territories from energy conservation efforts in the time
period of 2021 to 2040. To produce a reliable and transparent estimate of energy
efficiency (EE) resource potential, the AEG team performed the following tasks to meet
Avista’s key objectives:
▪Used information and data from Avista, as well as secondary data sources, to
describe how customers currently use gas by sector, segment, end use and
technology.
▪Developed a baseline projection of how customers are likely to use gas in absence
of future EE programs. This defines the metric against which future program
savings are measured. This projection used up-to-date technology data, modeling
assumptions, and energy baselines that reflect both current and anticipated
federal, state, and local energy efficiency legislation that will impact energy EE
potential.
▪Estimated the technical, achievable technical, and achievable economic potential
at the measure level for energy efficiency within Avista’s service territory over the
2021 to 2040 planning horizon.
▪Delivered a fully configured end-use conservation planning model, LoadMAP, for
Avista to use in future potential and resource planning initiatives
▪In summary, the potential study provided a solid foundation for the development of
Avista’s energy savings targets.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 54 of 184
Table ES-1 summarizes the results for Avista’s Washington territory at a high level. AEG
analyzed potential for the residential, commercial, and industrial market sectors. First-
year utility cost test (UCT) achievable economic potential in Washington is 75,820
dekatherms. This increases to a cumulative total of 173,838 dekatherms in the second
year and 1,386,479 dekatherms by the tenth year (2030).
Table ES-1: Washington Conservation Potential by Case, Selected Years
(dekatherms)
Scenario 2021 2022 2023 2030 2040
Baseline Forecast (Dth) 19,118,293 19,289,575 19,805,020 20,612,516 21,619,876
Cumulative Savings (Dth)
UCT Achievable Economic 75,820 173,838 457,423 1,386,479 3,560,512
Achievable Technical 41,871 416,584 1,221,810 3,183,398 6,309,826
Technical 187,983 897,098 2,314,334 5,084,999 8,908,493
Energy Savings (% of
Baseline)
UCT Achievable Economic
Potential 0.4% 0.9% 2.3% 6.7% 16.5%
Achievable Technical Potential 0.2% 2.2% 6.2% 15.4% 29.2%
Technical Potential 1.0% 4.7% 11.7% 24.7% 41.2%

Table ES-2 summarizes the results for Avista’s Idaho territory at a high level. First-year
utility cost test (UCT) achievable economic potential in Idaho is 35,816 dekatherms. This
increases to a cumulative total of 87,995 dekatherms in the second year and 737,710
dekatherms by the tenth year (2030).

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 55 of 184
Table ES-2: Idaho Conservation Potential by Case, Selected Years (dekatherms)
Scenario 2021 2022 2023 2030 2040
Baseline Forecast (Dth) 10,019,377 10,144,894 10,520,169 11,004,568 12,006,819
Cumulative Savings (Dth)
UCT Achievable Economic 35,816 87,995 229,283 737,710 2,025,410
Achievable Technical 26,220 226,613 657,997 1,722,830 3,544,048
Technical 102,031 490,826 1,273,202 2,777,509 5,013,697
Energy Savings (% of Baseline)
UCT Achievable Economic
Potential 0.4% 0.9% 2.2% 6.7% 16.9%
Achievable Technical Potential 0.3% 2.2% 6.3% 15.7% 29.5%
Technical Potential 1.0% 4.8% 12.1% 25.2% 41.8%

As part of this study, we also estimated total resource cost (TRC) potential, with the focus
of fully balancing non-energy impacts. This includes the use of full measure costs as well
as quantified and monetizable non-energy impacts and non-gas fuel impacts (e.g. electric
cooling or wood secondary heating) consistent with methodology within the 2021
Northwest Conservation and Electric Power Plan (2021 Plan). We explore this potential
in more detail throughout the report.
The entire CPA report including the methodology can be found in Appendix 3.1.

Energy Trust of Oregon - CPA
Energy Trust of Oregon, Inc. (Energy Trust) is an independent nonprofit organization
dedicated to helping utility customers in Oregon and southwest Washington benefit from
saving energy and generating renewable power. Energy Trust funding comes exclusively from
utility customers and is invested on their behalf in lowest-cost energy efficiency and clean,
renewable energy. In 1999, Oregon energy restructuring legislation (SB 1149) required
Oregon’s two largest electric utilities—PGE and Pacific Power—to collect a public purpose
charge from their customers to support energy conservation in K-12 schools, low-income
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 56 of 184
housing energy assistance, and energy efficiency and renewable energy programs for
residential and business customers.2

In 2001, Energy Trust entered into a grant agreement with the Oregon Public Utility
Commission (OPUC) to invest the majority of revenue from the 3 percent public purpose
charge in energy efficiency and renewable energy programs. Every dollar invested in energy
efficiency by Energy Trust will save residential, commercial, and industrial customers nearly
$3 in deferred utility investment in generation, transmission, fuel purchase and other costs.
Appreciating these benefits, natural gas companies asked Energy Trust to provide service to
their customers—NW Natural in 2003, Cascade Natural Gas in 2006 and Avista in 2017.
These arrangements stemmed from settlement agreements reached in Oregon Public Utility
Commission processes.
Energy Trust’s model of delivering energy efficiency programs as a single entity across the
five overlapping service territories of Oregon’s investor-owned gas and electric utilities has
experienced a great deal of success. Since its inception, Energy Trust has saved more than
783 aMW of electricity and 71 million annual therms. This equates to more than 32.7 million
tons of CO2 emissions avoided and is a significant factor contributing to the relatively flat or
lower energy sales observed by both gas and electric utilities from 2009 to 2018, as shown in
OPUC utility statistic books.3
Energy Trust serves residential, commercial, and firm industrial customers in Avista’s natural
gas service territory in the areas of Medford, Klamath Falls, and La Grande, Oregon. In 2019,
Energy Trust’s programs achieved savings of 384,000 therms—equivalent to 107% of the
established savings goal of 360,000 therms, as shown in Figure 3.1.

2 In 2007, Oregon’s Renewable Energy Act (SB 838) allowed the electric utilities to capture additional, cost-effective
electric efficiency above what could be obtained through the 3 percent charge, thereby avoiding the need to purchase
more expensive electricity. This new supplemental funding, combined with revenues from natural gas utility customers,
increased Energy Trust revenues from about $30 million in 2002 to $182 million in 2020.
3 OPUC 2018 Stat book – 10 Year Summary Tables: https://www.oregon.gov/puc/forms/Forms%20and%20Reports/2018-
Oregon-Utility-Statistics-Book.pdf
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 57 of 184
Figure 3.1: 2019 Achieved Savings vs. Goals for Avista Service Territory

In addition to administering energy efficiency programs on behalf of the utilities, Energy Trust
also provides each utility with a 20-year forecast of cost-effective energy efficiency savings
potential expected to be achieved by Energy Trust. The results are used by Avista and other
utilities in Integrated Resource Plans (IRP) to inform the energy efficiency resource potential
in their territory that can be used to meet their customers’ projected load.

Energy Trust 20-Year Forecast Methodology
20-Year Forecast Overview
Energy Trust developed a DSM resource forecast for Avista using its resource assessment
modeling tool (hereinafter the ”RA Model”) to identify the total 20-year cost-effective modeled
savings potential. This potential is subsequently ‘deployed’ exogenously of the model to
estimate the final savings forecast for each of the 20 years. There are four types of potential
that are calculated to develop the final savings potential estimate. These are shown in Figure
3.2 and discussed in greater detail in the sections below.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 58 of 184
Figure 3.2: Types of Potential Calculated in 20-Year Forecast Determination
Not
Technically
Feasible
Technical Potential
Calculated within
RA Model
Market
Barriers
Achievable Potential
Not Cost-
Effective
Cost-Effective Achievable
Potential
Program
Design &
Market
Penetration
Final Program
Savings
Potential
Developed with
Programs &
Other Market
Information

The RA Model utilizes the modeling platform Analytica®4, an object-flow based modeling
platform that is designed to visually show how different objects and parts of the model
interrelate and flow throughout the modeling process. The model utilizes multidimensional
tables and arrays to compute large, complex datasets in a relatively simple user interface.
Energy Trust then deploys this cost-effective potential exogenously to the RA model into an
annual savings projection based on past program experience, knowledge of current and
developing markets, and future codes and standards. This final 20-year savings projection is
provided to Avista for inclusion in in their SENDOUT® Model as a reduction to demand on
the system.
20-Year Forecast Detailed Methodology
Energy Trust’s 20-year forecast for DSM savings follows six overarching steps from initial
calculations to deployed savings, as shown in Figure 3.3. The first five steps in the varying
shades of blue nodes - Data Collection and Measure Characterization to Cost-Effective
Achievable Energy Efficiency Potential - are calculated within Energy Trust’s RA Model. This
results in the total cost-effective potential that is achievable over the 20-year forecast. The
actual deployment of these savings (the acquisition percentage of the total potential each
year, represented in the green node of the flow chart) is done exogenously of the RA model.
The remainder of this section provides further detail on each of the steps shown below.

4 http://www.lumina.com/why-analytica/what-is-analytica1/
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 59 of 184
Figure 3.3: Energy Trust’s 20-Year DSM Forecast Determination Flow Chart

1. Data Collection and Measure Characterization
The first step of the modeling process is to identify and characterize a list of measures to
include in the model, as well as receive and format utility ‘global’ inputs for use in the
model. Energy Trust compiles and loads a list of commercially available and emerging
technology measures for residential, commercial, industrial, and agricultural applications
installed in new or existing structures. The list of measures is meant to reflect the full suite
of measures offered by Energy Trust, plus a spectrum of emerging technologies.5 In
addition to identifying and characterizing applicable measures, Energy Trust collects
necessary data to scale the measure level savings to a given service territory (known as
‘global inputs’).
5 An emerging technology is defined as technology that is not yet commercially available but is in some stage of
development with a reasonable chance of becoming commercially available within a 20-year timeframe. The model is capable of quantifying costs, potential, and risks associated with uncertain, but high-saving emerging technology
measures. The savings from emerging technology measures are reduced by a risk-adjustment factor based on what stage of development the technology is in. The working concept is that the incremental risk-adjusted savings from emerging
technology measures will result in a reasonable amount of savings over standard measures for those few technologies that
eventually come to market without having to try and pick winners and losers.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 60 of 184
• Measure Level Inputs:
Once the measures have been identified for inclusion in the model, they must be
characterized in order to determine their savings potential and cost-effectiveness.
The characterization inputs are determined through a combination of Energy Trust
primary data analysis, regional secondary sources6, and engineering analysis.
There are over 30 measure level inputs that feed into the model, but on a high level,
the inputs are organized into the following categories:

1. Measure Definition and Equipment Identification: This is the definition of
the efficient equipment and the baseline equipment it is replacing (e.g., a
95% AFUE furnace replacing an 80% AFUE baseline furnace). A measure’s
replacement type is also determined in this step – retrofit, replace on
burnout, or new construction.
2. Measure Savings: natural gas savings associated with an efficient measure
calculated by comparing the baseline and efficient measure consumptions.
3. Incremental Costs: The incremental cost of an efficient measure over the
baseline. The definition of incremental cost depends upon the replacement
type of the measure. If a measure is a retrofit measure, the incremental cost
of a measure is the full cost of the equipment and installation. If the measure
is a replace on burnout or new construction measure, the incremental cost
of the measure is the difference between the cost of the efficient measure
and the cost of the baseline equipment.
4. Market Data: Market data of a measure includes the density, saturation, and
suitability of a measure. The density is the number of measure units that can
be installed per scaling basis (e.g., the average number of showers per
home for showerhead measures). Saturation is the share of equipment that
is already efficient (e.g., 50% of the showers already have a low flow
showerhead). Suitability of a measure is a percentage that represents the
percent of installation opportunities where the measure can actually be
installed. For example, a duct sealing measure would need to reflect the
share of homes that actually have ducted heating systems. These data
inputs are generally derived from regional market data sources such as
NEEA’s Residential and Commercial Building Stock Assessments.
• Utility Global Inputs:
The RA Model requires several utility-level inputs to create the DSM forecast.
These inputs include:
6 Secondary Regional Data sources include: The Northwest Power Planning Council (NWPPC), the Regional Technical
Forum (the technical arm of the NWPPC), and market reports such as NEEA’s Residential and Commercial Building Stock
Assessments (RBSA and CBSA)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 61 of 184
1. Customer and Load Forecasts: These inputs are essential to scale the
measure level savings to a utility service territory. For example,
residential measures are characterized on a ‘per home’ scaling basis, so
the measure densities are calculated as the number of measures per
home. The model then takes the number of homes that Avista has
forecasted to scale the measure level potential to their entire service
territory.
2. Customer Stock Demographics: These data points are utility specific
and identify the percentage of customer building stock that utilize
different fuels for space and water heating. The RA Model uses these
inputs to segment the total stock to the portion that is applicable to a
measure (e.g., gas water heaters are only applicable to customers that
have gas water heat).
3. Utility Avoided Costs: Avoided costs are the net present value of
avoided energy purchases and delivery costs associated with energy
savings. Energy Trust calculates these values based on inputs provided
by Avista. The avoided cost components are discussed in other sections
of this IRP. Avoided costs are the primary benefit of energy efficiency in
the cost-effectiveness screen.

2. Calculate Technical Energy Efficiency Potential
Once measures have been characterized and utility data loaded into the model, the next
step is to determine the technical potential of energy that could be saved. Technical
potential is defined as the total energy savings potential of a measure that could be
achieved regardless of cost or market barriers, representing the maximum potential
energy savings available. The model calculates technical potential by multiplying the
number of applicable units of a measure in the service territory by the measure’s savings.
The model determines the total number of applicable units for a measure utilizing several
of the measure level and utility inputs referenced above:

Total applicable
units =
Measure Density * Baseline Saturation * Suitability
Factor * Heat Fuel Multipliers (if applicable) * Total
Utility Stock (e.g., # of homes)
Technical
Potential = Total Applicable Units * Measure Savings

This savings potential does not consider the various cost and market barriers that will limit
the adoption of efficiency measures.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 62 of 184
3. Calculate Achievable Energy Efficiency Potential
Achievable potential is simply a reduction of the technical potential to account for market
barriers that prevent the adoption of the measures identified in the technical potential. This
is done by applying a factor to reflect the maximum achievability for each measure. For
Avista’s 2020 IRP, Energy Trust updated its methodology to reflect the maximum
achievability estimated by the Northwest Power and Conservation Council for the 2021
Power Plan. While in past power plans a universal assumption of 85% was used, these
factors now typically range from 85% to 95%.7

Achievable
Potential = Technical Potential * Maximum Achievability Factor

4. Determine Cost-effectiveness of Measure using TRC Screen
The RA Model screens all DSM measures in every year of the forecast horizon using the
Total Resource Cost (TRC) test. This test evaluates the total present value of all benefits
attributable to the measure divided by the total present value of all costs. A TRC test value
greater than or equal to 1.0 means the value of benefits is equal to or exceeds the costs
and the measure is cost-effective and contributes to the total amount of cost-effective
potential. The TRC is expressed formulaically as follows:

TRC = Present Value of Benefits / Present Value of Costs

Where the Present Value of Benefits includes the sum of the following two
components:
a) Avoided Costs: The present value of natural gas energy saved over the life of
the measure, as determined by the total therms saved multiplied by Avista’s
avoided cost per therm. The net present-value of these benefits is calculated
based on the measure’s expected lifespan using the company’s discount rate.
b) Non-energy benefits are also included when present and quantifiable by a
reasonable and practical method (e.g., water savings from low-flow
showerheads or operations and maintenance cost reductions from advanced
controls).

Where the Present Value of Costs includes:
a) Incentives paid to the participant; and
7 For details on this, see https://www.nwcouncil.org/sites/default/files/2019_0813_p5.pdf.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 63 of 184
b)The participant’s remaining out-of-pocket costs for the installed cost of the
measures after incentives, minus state and federal tax credits.
The cost-effectiveness screen is a critical component for Energy Trust modeling and
program planning because Energy Trust is only allowed to incentivize cost-effective
measures unless an exception has been granted by the OPUC.
5.Quantify the Cost-Effective Achievable Energy Efficiency Potential
The RA Model’s final output of potential is the quantified cost-effective achievable
potential. If a measure passes the TRC test described above, then the achievable savings
from a measure is included in this potential. If the measure does not pass the TRC test
above, the measure’s potential is not included in cost-effective achievable potential.
However, the cost-effectiveness screen is overridden for some measures under two
specific conditions:
1)The OPUC has granted an exception to offer non-cost-effective measures under
strict conditions or,
2)When the measure is not cost-effective using utility-specific avoided costs, but the
measure is cost-effective when using blended gas avoided costs for all of the gas
utilities Energy Trust serves and is therefore offered by Energy Trust programs.
6.Deployment of Cost-Effective Achievable Energy Efficiency Potential
After determining the 20-year cost-effective achievable modeled potential, Energy Trust
develops a savings projection based on past program experience, knowledge of current
and developing markets, and future codes and standards. The savings projection is a 20-
year forecast of energy savings that will result in a reduction of load on Avista’s system.
This savings forecast includes savings from program activity for existing measures and
emerging technologies, expected savings from market transformation efforts that drive
improvements in codes and standards, and a forecast of savings from very large projects
that are not characterized in Energy Trust’s RA Model but consistently appear in Energy
Trust’s historic savings record and have been a source of overachievement against IRP
targets in prior years for other utilities that Energy Trust serves.
Figure 3.4 below reiterates the types of potential shown in Figure 3.2, and how the steps
described above and in the flow chart fit together.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 64 of 184
Figure 3.4: The Progression to Program Savings Projections
Data Collection and Measure Characterization Step 1
Not
Technically
Feasible
Technical Potential Step 2
Market
Barriers
Achievable Potential Step 3
Not Cost-
Effective
Cost-Effective Achievable
Potential Steps 4 & 5
Program
Design &
Market
Penetration
Final Program
Savings
Potential
Step 6

Forecast Results
The results of Energy Trust’s forecast are shown below.
RA Model Results – Technical, Achievable and Cost-Effective Achievable Potential
The RA Model produces results by potential type, as well as several other useful outputs,
including a supply curve based on the levelized cost of energy efficiency measures. This
section discusses the overall model results by potential type and provides an overview of the
supply curve. These results do not include the application of ramp rates applied in Step 6
described above.
Forecasted Savings by Sector
Table 3.3 summarizes the technical, achievable, and cost-effective potential for Avista’s
system in Oregon. These savings represent the total 20-year cumulative savings potential
identified in the RA Model by the three types identified in Figure 3.4 above. Modeled savings
represent the full spectrum of potential identified in Energy Trust’s resource assessment
model through time, prior to deployment of these savings into the final annual savings
projection.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 65 of 184
Table 3.3: Summary of Cumulative Modeled Savings Potential - 2021–2040
Sector
Technical
Potential
(Million Therms)
Achievable
Potential
(Million Therms)
Cost-Effective
Achievable Potential
(Million Therms)
Residential 16.9 15.2 12.1
Commercial 7.8 6.8 5.7
Industrial 0.3 0.2 0.2
Total 24.9 22.2 18.0

Figure 3.5 shows cumulative forecasted savings potential across the three sectors Energy
Trust serves, as well as the type of potential identified in Avista’s service territory. Residential
sales make up the majority of Avista’s service in Oregon, which is reflected in the potential.
Firm industrial sales represent a small percentage of the total sales in Oregon for Avista, and
subsequently shows very little savings potential. Avista’s interruptible and transport
customers are not eligible to participate in Energy Trust programs. 85% of the industrial
technical potential is cost-effective, while in the residential and commercial sectors, cost-
effective achievable potential is 72% and 73% of technical potential, respectively.

Figure 3.5: Savings Potential by Sector and Type – Cumulative 2021–2040 (Millions of
Therms)

-
2
4
6
8
10
12
14
16
18
Residential Commercial Industrial
Mil
l
i
o
n
s

o
f

T
h
e
r
m
s
Technical Achievable Cost-effective Achievable
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 66 of 184
Cost-Effective Achievable Savings by End-Use
Figure 3.6 below provides a breakdown of Avista’s 20-year cost-effective savings potential by
end use.

Figure 3.6: 20-Year Cost-Effective Cumulative Potential by End Use

As is typical for a gas utility, the top saving end uses are heating, water heating, and
weatherization. A large portion of the water heating end-use is attributable to new construction
homes due to how Energy Trust assigns end uses to the New Homes pathways offered
through Energy Trust’s residential programs. The New Home pathways are packages of
measures in new construction homes with savings that span several end-uses. Energy Trust
assigns an end-use to each of the New Homes pathways based on the end-use that achieves
the most significant savings in the package. For example, the most cost-effective New Home
pathway that was identified by the model (because it achieves the most savings for the least
cost) was designated as a water heating end-use, though the package includes several other
efficient gas equipment measures.

In addition to the New Homes pathway savings, the water heating end-use includes water
heating equipment from all sectors, as well as showerheads and aerators. Heating,
weatherization, and HVAC end uses represent the savings associated with space heating
equipment, retrofit add-ons, and new construction packages. The behavioral end use consists
primarily of potential from Energy Trust’s commercial strategic energy management measure,
a service where Energy Trust energy experts provide training and support to facilities teams
0.03
0.04
0.16
0.33
0.42
0.56
0.71
4.80
5.14
5.78
- 1 2 3 4 5 6 7
HVAC
Appliance
Process Heating
Cooking
Ventilation
Behavioral
Other
Weatherization
Water Heating
Heating
Millions of Therms
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 67 of 184
and staff to identify operations and maintenance changes that make a difference in a
building’s energy use.
Contribution of Emerging Technologies
As mentioned earlier in this report, Energy Trust includes a suite of emerging technologies in
its model. The emerging technologies included in the model are listed in Table 3.4.
Table 3.4: Emerging Technologies Included in the Model
Residential Commercial Industrial
• Path 5 Emerging Super-
Efficient Whole Home
• Window Replacement
(U<.20)
• Absorption Gas Heat Pump
Water Heaters
• Advanced Insulation
• DOAS/HRV
• Gas-fired Heat Pump
Hot Water
• Gas-fired Heat Pump,
Heating
• Advanced Windows
• Gas-fired Heat Pump
Water Heater
• Wall Insulation-
Vacuum Insulated
Panel, R0-R35

Energy Trust recognizes that emerging technologies are inherently uncertain and utilizes a
risk factor to hedge against that uncertainty. The risk factor for each emerging technology is
used to characterize the inherent uncertainty in the ability for emerging technologies to
produce reliable future savings. This risk factor is determined based on qualitative risk
categories, including:
• Market risk
• Technical risk
• Data source risk

The framework for assigning the risk factor is shown in Table 3.5. Each emerging technology
was assessed within each risk category and then a total weighted score was then calculated.
Well-established and well-studied technologies have lower risk factors and nascent,
unevaluated technologies (e.g., gas absorption heat pump water heaters) have higher risk
factors. This risk factor is then applied as a multiplier to reduce the incremental savings
potential of the measure.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 68 of 184
Table 3.5: Emerging Technology Risk Factor Score Card

Figure 3.7 shows the amount of emerging technology savings within each type of potential.
While emerging technologies make up a relatively large percentage of the technical and
achievable potential, nearly 25%, once the cost-effectiveness screen is applied, the relative
share of emerging technologies drops to 20% of total cost-effective achievable potential. This
is because some of these technologies are still in early stages of development and are quite
expensive. Though Energy Trust includes factors to account for forecasted decreases in cost
Emerging Technology Risk Factor
Risk
Category 10% 30% 50% 70% 90%
Market Risk
(25%
weighting)
High Risk:
• Requires new/changed
business model
• Start-up, or small
manufacturer
• Significant changes to
infrastructure
• Requires training of
contractors. Consumer
acceptance barriers exist.

Low Risk:
• Trained contractors
• Established business
models
• Already in U.S. Market
• Manufacturer committed
to commercialization
Technical
Risk
(25%
weighting)
High Risk:
Prototype in
first field
tests.
A single or
unknown
approach
Low volume
manufacturer.
Limited
experience
New product
with broad
commercial
appeal
Proven
technology
in different
application
or different
region
Low Risk:
Proven
technology
in target
application.
Multiple
potentially
viable
approaches.
Data Source
Risk
(50%
weighting)
High Risk:
Based only
on
manufacturer
claims
Manufacturer
case studies
Engineering
assessment
or lab test
Third party
case study
(real world
installation)
Low Risk:
Evaluation
results or
multiple
third-party
case studies
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 69 of 184
and increased savings from these technologies over time where applicable, some are not
cost-effective at any point over the planning horizon.
Figure 3.7: Cumulative Contribution of Emerging Technologies by Potential Type

Cost-Effective Override Effect
Table 3.6 shows the savings potential in the RA model that was added by employing the cost-
effectiveness override option in the model. As discussed in the methodology section, the
cost-effectiveness override option forces non-cost-effective potential into the cost-effective
potential results and is used when a measure meets one of the following two criteria:
1. A measure is offered under an OPUC exception.
2. When the measure is not cost-effective using Avista-specific avoided costs, but the
measure is cost-effective when using blended gas avoided costs for all of the gas
utilities Energy Trust serves and is therefore offered by Energy Trust programs.

Table 3.6: Cumulative Cost-Effective Potential (2021-2040) due to Cost-Effectiveness
Override (Millions of therms)
Sector
With Cost
Effectiveness
Override
Without Cost
Effectiveness
Override
Difference
Residential 12.1 10.9 (1.2)
Commercial 5.7 5.7 -
Industrial 0.2 0.2 -
Total 18.0 16.8 (1.2)
24%23%
20%
0
5
10
15
20
25
30
Technical Achievable Cost-effective
Achievable
Mil
l
i
o
n
s

o
f

T
h
e
r
m
s
Conventional Emerging
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 70 of 184
In this IRP, approximately 7% of the cost-effective potential identified by the model is due to
the use of the cost-effective override. The measures that had this option applied to them
included residential attic, floor, and wall insulation, clothes dryers, certain new homes
packages, and clothes washers in the commercial sector.
Supply Curves and Levelized Cost Outputs
An additional output of the RA Model is a resource supply curve developed from the levelized
cost of energy of each measure. The supply curve graphically depicts the total potential that
could be saved at various costs. The levelized cost provides a consistent basis for comparing
efficiency measures and other resources with different lifetimes. The levelized cost calculation
starts with the incremental cost of a given measure. The total cost is amortized over the
estimated measure lifetime using the Avista’s discount rate. The annualized measure cost is
then divided by the annual natural gas savings. Some measures have negative levelized
costs because these measures have non-energy benefits that are greater than the total cost
of the measure over the same period.

Figure 3.8 below shows the supply curve developed for this IRP that can be used for
comparing demand-side and supply-side resources. The cost-effective potential identified in
this assessment is approximately 18 million therms, which translates to approximately
$2.40/therm on this graph. This is not a precise point, however, since measures around this
point will save natural gas at different times in relation to Avista’s peak periods and therefore
have varying capacity values that function to make them more or less c ost-effective.
Consequently, measures on either side of this point may or may not be cost effective. Finally,
after approximately $3/therm, additional potential comes at rapidly increasing cost
increments.

Figure 3.8: Natural Gas Supply Curve

-
5
10
15
20
25
-$5 -$3 -$1 $1 $3 $5 $7 $9
Cu
m
u
l
a
t
i
v
e

P
o
t
e
n
t
i
a
l

(
M
i
l
l
i
o
n
s

of

T
h
e
r
m
s
)
TRC Levelized Cost ($/therm)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 71 of 184
Deployed Results – Final Savings Projection
The results of the final savings projection show that Energy Trust can achieve 2.1 million
annual therm savings across Avista’s system in Oregon from 2021 to 2025 and nearly 14.8
million therms by the end of 2040. This represents a 14.4 percent cumulative load reduction
by 2040 and is an average of just under a 0.8 percent incremental annual load reduction. The
cumulative final savings projection is shown in Table 3.7, which compares the technical,
achievable, and cost –effective achievable potential for comparison.
Table 3.7: 20-Year Cumulative Savings Potential by Type (Millions of Therms)
Technical
Potential
Achievable
Potential
Achievable
Cost-Effective
Potential
Energy Trust
Deployed Savings
Projection
Residential 16.9 15.2 12.1 8.2
Commercial 7.8 6.8 5.7 6.1
Industrial 0.3 0.2 0.2 0.5
Total 24.9 22.2 18.0 14.8
The final deployed savings projection is less than the modeled cost-effective achievable
potential. The primary reason for this additional step down in savings is lost opportunity
measures. These measures are meant to replace failed equipment or be installed in new
construction. They are considered lost opportunity measures because programs have one
opportunity to influence the installation of efficient equipment when the existing equipment
fails or when the new building is built. This is because these measures must be installed at
that specific point in time, and if the efficient equipment is not installed, then the opportunity
is lost until the equipment fails again. Energy Trust assumes that most lost opportunity
measures have gradually increasing annual adoption rates as time passes due to increasing
program influence and increasing codes and standards.
However, in the commercial and industrial sectors, the final Energy Trust savings projection
is higher than the model-identified cost-effective potential. In the commercial sector, new
construction savings are difficult to adequately represent in the model and program forecasts
exceed the available potential quantified in the RA model. The industrial sector projection is
higher because it includes an adder for large projects that are not forecast by the RA model
but are nonetheless expected to be acquired over time.
Figure 3.9 below shows the annual savings projection by end use. The savings acquisitions
in the initial years are fairly flat due to expected market conditions. After this point, expected
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 72 of 184
program savings ramp up over the forecast period, to achieve as much cost-effective potential
as possible.
Figure 3.9: Annual Deployed Final Savings Potential by End Use

Finally, Figure 3.10 shows the annual and cumulative savings as a percentage of Avista’s
load forecast in Oregon. Annually, the savings as a percentage of load varies from about 0.4%
at its lowest to just under 1% at its highest, as represented on the left axis and the blue line.
Cumulatively, the savings as a percentage of load builds to 14.4% by 2040, as shown on the
right axis and the gold line.

Heating
Water Heating
Weatherization
-
0.2
0.4
0.6
0.8
1.0
1.2
20
2
1
20
2
3
20
2
5
20
2
7
20
2
9
20
3
1
20
3
3
20
3
5
20
3
7
20
3
9
Mi
l
l
i
o
n
s

o
f

T
h
e
r
m
s
Large Project Adder
Weatherization
Water Heating
Ventilation
Process Heating
Other
Heating
Cooking
Behavioral
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 73 of 184
Figure 3.10: Annual and Cumulated Forecasted Savings as a Percentage of Avista
Load Forecast

Deployed Results – Peak Day Results
In the state of Oregon and around the region, there is an increased focus on the peak savings
contributions of energy efficiency and their impact on capacity investments. This new focus
has led some utilities to embark on targeted load management efforts for avoiding or delaying
distribution system reinforcements. Therefore, Avista and Energy Trust have collaborated to
develop estimates of peak day contributions from the energy efficiency measures that Energy
Trust forecasts to install.

Peak day coincident factors are the percentage of annual savings that occur on a peak day
and are shown in Table 3.8 below. Avista is still reviewing this methodology and for the
purpose of this analysis, Energy Trust utilized the peak day factors that are used in the
avoided costs used to screen measure for cost-effectiveness to determine the cost-effective
achievable resource per the description above. These include residential and commercial
space heating factors developed by NW Natural in and hot water, process load (flat), and
clothes washer factors sourced from load shapes developed by the Northwest Power and
Conservation Council for electric measures that are analogous to gas equipment. The peak
day factors are the highest for the space heating load shapes, which aligns with a typical
0%
2%
4%
6%
8%
10%
12%
14%
16%
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039
0.0%
0.2%
0.4%
0.6%
0.8%
1.0%
1.2%
Cu
m
u
l
a
t
i
v
e

S
a
v
i
n
g
s

a
s

%

o
f

L
o
a
d
An
n
u
a
l

S
a
v
i
n
g
s

a
s

%

o
f

A
n
n
u
a
l

L
o
a
d

Annual Cumulative
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 74 of 184
winter system peak of natural gas utilities. These peak day factors will be reviewed and
updated by Avista to be specific to Avista’s Oregon service territory in the next IRP.
Table 3.8: Peak Day Coincident Factors by Load Profile
Load Profile Peak Day Factor Source
Residential Space Heating 2.10% NW Natural
Commercial Space Heating 1.80% NW Natural
Water Heating 0.40% NWPCC
Clothes Washer 0.20% NWPCC
Process Load 0.30% NWPCC

Figure 3.11 below shows the annual, deployed peak day savings potential based upon the
results of the 20-year forecast developed for this IRP. Each measure analyzed is assigned a
load shape and the appropriate peak day factor is applied to the annual savings to calculate
the overall DSM contribution to peak day capacity. Cumulatively, this is equal to 207,427
therms, or 1.4% of the total deployed savings potential in Avista’s Oregon service territory
over the 20-year forecast, as shown below.

Figure 3.11: Annual Deployed Peak Day DSM Savings Contribution by Sector

-
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039
De
p
l
o
y
e
d

P
e
a
k

D
a
y

S
a
v
i
n
g
s

(
T
h
e
r
m
s
)
Commercial Industrial Residential
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 75 of 184
Table 3.9: Cumulative Deployed Peak Day DSM Savings Contribution by Sector
(Therms)
Sector Cumulative Peak Day
Savings (Therms)
% of Overall Sector
Savings
Commercial 76,529 1.3%
Residential 129,245 1.6%
Industrial 1,653 0.3%
Total 207,427 1.4%

Conclusion
Avista has a long-term commitment to responsibly pursuing all available and cost-effective
efficiency options as an important means to reduce its customer’s energy cost. Cost-effective
demand-side management options are a key element in the Company’s strategy to meet
those commitments. Falling avoided costs and lower growth in customer demand have led to
a reduced role for conservation in the overall natural gas portfolio compared with IRPs done
prior to 2012, however, a regulatory shift to utilizing the UCT in Washington and Idaho DSM
programs will continue to provide a vital role in offsetting future natural gas load growth. The
company transitioned its Oregon DSM regular income, commercial, and industrial customer
programs to the Energy Trust of Oregon (ETO), with the ETO being the sole administrator
effective January 1, 2017. Avista is continuing to adaptively manage its DSM programs in
response to the ever-shifting economic climate.
Market transformation is not itself called out within the CPA since the CPA focuses upon
conservation potential without regard to how that potential is achieved. The prospect for a
regional market transformation entity will potentially bring a valuable tool to bear in working
towards the achievement of the cost-effective conservation opportunities identified within the
natural gas CPA.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 76 of 184
4: Supply-Side Resources
Overview
Avista analyzed a range of future demand scenarios and possible cost-effective
conservation measures to reduce demand. This chapter discusses supply options to meet
net energy demand. Avista’s objective is to provide reliable service at reasonable prices.
To help achieve this objective, Avista evaluates a variety of supply-side resources and
attempts to build a diversified natural gas supply portfolio. The resource acquisition and
commodity procurement programs resulting from the evaluation consider physical and
financial risks, market-related risks, and procurement execution risks; and identifies
methods to mitigate these risks.
Avista manages natural gas procurement and related activities on a system-wide basis
with several regional supply options available to serve core customers. Supply options
include firm and non-firm supplies, firm and interruptible transportation on six interstate
pipelines, and storage. Because Avista’s core customers span three states, the diversity
of delivery points and demand requirements adds to the options available to meet
customers’ needs. The utilization of these components varies depending on demand and
operating conditions. This chapter discusses the available regional commodity resources
and Avista’s procurement plan strategies, the regional pipeline resource options available
to deliver the commodity to customers, and the storage resource options available to
provide additional supply diversity, enhanced reliability, favorable price opportunities, and
flexibility to meet a varied demand profile. Carbon reducing supplies, such as renewable
natural gas (RNG) and hydrogen (H2) are also considered.

Commodity Resources
Supply Basins
The Northwest continues to enjoy a low-cost commodity environment with abundant
supply availability, especially when compared across the globe. This is primarily due to
the production in areas of the Northeast and Southern United States. This supply is
serving an increasing amount of demand in the population heavy areas in the middle and
eastern portions of Canada and the U.S displacing supplies that had historically been
delivered from the Western Canadian Sedimentary Basis (WCSB). Current forecasts
show a long-term regional price advantage for Western Canada and Rockies gas basins
as the need for this gas diminishes. High Canadian production paired with limited options
for flowing gas into demand areas has created a, generally, discounted commodity in the
Northwest when compared to the Henry Hub. Although stalled due to an oil price collapse
in 2020, associated gas from oil wells is still providing a large amount of the natural gas
supply. Access to these abundant supplies of natural gas and to major markets across
the continent has also led to the construction of multiple LNG plants. These LNG plants
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 77 of 184
will be a large demand addition to North American supply. There are a few LNG export
facilities in the Western half of North America. The first is Jordan Cove and although
approved by FERC, it is not expected to be built in the long-term outlook from Wood
Mackenzie. The second is Canadian project known LNG Canada and is in Kitimat B.C.
This facility is one of the largest investments in Canadian history and is currently under
construction. Its initial capacity, like Jordan Cove, is roughly 1 Bcf per day, but contains
an option for up to 3.5 Bcf per day in total. The large increase of natural gas demand by
either of these facilities moving forward could cause pressure on commodity prices with
the limited infrastructure in the Pacific Northwest.
Another relatively new demand area is Mexico. In 2013, Mexico reformed its energy
sector allowing new market participants, innovative technologies and foreign investment.
This market reformation opened new opportunities for natural gas export to Mexico.
Since these market changes, Mexican imports which were historically less than 2 Bcf per
day have more than doubled to over 5 Bcf per day.
Recent estimates from both the EIA and Natural Resources Canada reflect a large
potential supply of natural gas in North America of over 4,000 trillion cubic feet (Tcf) or
enough supply to last many decades at current demand levels. This estimate is based on
known geological areas combined with the ability to economically recover natural gas as
infrastructure expands and technology improves.
Regional Market Hubs
There are numerous regional market hubs in the Pacific Northwest where natural gas is
traded extending from the two primary basins. These regional hubs are typically located
at pipeline interconnects. Avista is located near, and transacts at, most of the Pacific
Northwest regional market hubs, enabling flexible access to geographically diverse
supply points. These supply points include:
• AECO – The AECO-C/Nova Inventory Transfer market center located in Alberta is
a major connection region to long-distance transportation systems which take
natural gas to points throughout Canada and the United States. Alberta is the
primary Canadian exporter of natural gas to the U.S. and historically produces 90
percent of Canada's natural gas.
• Rockies – This pricing point represents several locations on the southern end of
the NWP system in the Rocky Mountain region. The system draws on Rocky
Mountain natural gas-producing areas clustered in areas of Colorado, Utah, New
Mexico and Wyoming.
• Sumas/Huntingdon – The Sumas, Washington pricing point is on the
U.S./Canadian border where the northern end of the NWP system connects with
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 78 of 184
Enbridge’s Westcoast Pipeline and predominantly markets Canadian natural gas
from Northern British Columbia.
• Malin – This pricing point is at Malin, Oregon, on the California/Oregon border
where TransCanada’s Gas Transmission Northwest (GTN) and Pacific Gas &
Electric Company connect.
• Station 2 – Located at the center of the Enbridge’s Westcoast Pipeline system
connecting to northern British Columbia natural gas production.
• Stanfield – Located near the Washington/Oregon border at the intersection of the
NWP and GTN pipelines.
• Kingsgate – Located at the U.S./Canadian (Idaho) border where the GTN pipeline
connects with the TransCanada Foothills pipeline.

Given the ability to transport natural gas across North America, natural gas pricing is often
compared to the Henry Hub price. Henry Hub, located in Louisiana, is the primary natural
gas pricing point in the U.S. and is the trading point used in NYMEX futures contracts.
Figure 4.1 shows historic natural gas prices for first-of-month index physical purchases
at AECO, Station 2, Rockies and Henry Hub. The figure has changed in recent years due
to an alteration in flows of natural gas specifically coming from Western Canada.
Figure 4.1: Monthly Index Prices

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 79 of 184
Northwest regional natural gas prices typically move together; however, the basis
differential can change depending on market or operational factors. This includes
differences in weather patterns, pipeline constraints, and the ability to shift supplies to
higher-priced delivery points in the U.S. or Canada. By monitoring these price shifts,
Avista can often purchase at the lowest-priced trading hubs on a given day, subject to
operational and contractual constraints.
Liquidity is generally sufficient in the day-markets at most Northwest supply points. AECO
continues to be the most liquid supply point, especially for longer-term transactions.
Sumas has historically been the least liquid of the four major regional supply points
(AECO, Rockies, Sumas and Malin). This illiquidity contributes to generally higher relative
prices in the high demand winter months.
Avista procures natural gas via contracts. Contract specifics vary from transaction-to-
transaction, and many of those terms or conditions affect commodity pricing. Some of the
terms and conditions include:
• Firm vs. Non-Firm: Most term contracts specify that supplies are firm except for
force majeure conditions. In the case of non-firm supplies, the standard provision
is that they may be cut for reasons other than force majeure conditions.
• Fixed vs. Floating Pricing: The agreed-upon price for the delivered gas may be
fixed or based on a daily or monthly index.
• Physical vs. Financial: Certain counterparties, such as banking institutions, may
not trade physical natural gas, but are still active in the natural gas markets. Rather
than managing physical supplies, those counterparties choose to transact
financially rather than physically. Financial transactions provide another way for
Avista to financially hedge price.
• Load Factor/Variable Take: Some contracts have fixed reservation charges
assessed during each of the winter months, while others have minimum daily or
monthly take requirements. Depending on the specific provisions, the resulting
commodity price will contain a discount or premium compared to standard terms.
• Liquidated Damages: Most contracts contain provisions for symmetrical penalties
for failure to take or supply natural gas.

For this IRP, the SENDOUT® model assumes natural gas purchases under a firm,
physical, fixed-price contract, regardless of contract execution date and type of contract.
Avista pursues a variety of contractual terms and conditions to capture the most value for
customers. Avista‘s natural gas buyers actively assess the most cost-effective way to
meet customer demand and optimize unutilized resources.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 80 of 184
Transportation Resources
Although proximity to liquid market hubs is important from a cost perspective, supplies
are only as reliable as the pipeline transportation from the hubs to Avista’s service
territories. Capturing favorable price differentials and mitigating price and operational risk
can also be realized by holding multiple pipeline transportation options. Avista contracts
for a sufficient amount of diversified firm pipeline capacity from various receipt and
delivery points (including storage facilities), so that firm deliveries will meet peak day
demand. This combination of firm transportation rights to Avista’s service territory, storage
facilities and access to liquid supply basins ensure peak supplies are available to serve
core customers. The regional map, from the Northwest Gas Association (NWGA), shows
the relative capacity of the pipelines and storage capacity (Figure 4.2)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 81 of 184
Figure 4.2: Regional Pipeline and Storage Capacity

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 82 of 184
The major pipelines servicing the region include:
• Williams - Northwest Pipeline (NWP):
A natural gas transmission pipeline serving the Pacific Northwest moving natural
gas from the U.S./Canadian border in Washington and from the Rocky Mountain
region of the U.S.
• TransCanada Gas Transmission Northwest (GTN): A natural gas transmission
pipeline originating at Kingsgate, Idaho, (Canadian/U.S. border) and terminating
at the California/Oregon border close to Malin, Oregon.
• TransCanada Alberta System (NGTL): This natural gas gathering and
transmission pipeline in Alberta, Canada, delivers natural gas into the
TransCanada Foothills pipeline at the Alberta/British Columbia border.
• TransCanada Foothills System: This natural gas transmission pipeline delivers
natural gas between the Alberta - British Columbia border and the Canadian/U.S.
border at Kingsgate, Idaho.
• TransCanada Tuscarora Gas Transmission: This natural gas transmission
pipeline originates at Malin, Oregon, and terminates at Wadsworth, Nevada.
• Enbridge - Westcoast Pipeline: This natural gas transmission pipeline originates
at Fort Nelson, British Columbia, and terminates at the Canadian/U.S. border at
Huntington, British Columbia/Sumas, Washington.
• El Paso Natural Gas - Ruby pipeline: This natural gas transmission pipeline
brings supplies from the Rocky Mountain region of the U.S. to interconnections
near Malin, Oregon.

Avista has contracts with all of the above pipelines (with the exception of Ruby Pipeline)
for firm transportation to serve core customers. Table 4.1 details the firm
transportation/resource services contracted by Avista. These contracts are of different
vintages with different expiration dates; however, all have the right to be renewed by
Avista. This gives Avista and its customer’s available capacity to meet existing core
demand now and in the future.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 83 of 184
Table 4.1: Firm Transportation Resources Contracted (Dth/Day)
Avista North Avista South
Firm
Transportation Winter Summer Winter Summer
NWP TF-1 157,869 157,869 42,699 42,699
GTN T-1 100,605 75,782 42,260 20,640
NWP TF-2 91,200 2,623
Total 349,674 233,651 87,582 63,339
Firm Storage Resources - Max Deliverability
Jackson Prairie 346,667 54,623

*Represents original contract amounts after releases expire

Avista defines two categories of interstate pipeline capacity. Direct-connect pipelines
deliver supplies directly to Avista’s local distribution system from production areas,
storage facilities or interconnections with other pipelines. Upstream pipelines deliver
natural gas to the direct-connect pipelines from remote production areas, market centers
and out-of-area storage facilities. Firm Storage Resources - Max Deliverability is
specifically tied to Avista’s withdrawal rights at the Jackson Prairie storage facility and is
based on our one third ownership rights. This number only indicates how much we can
withdraw from the facility, as transport on NWP is needed to move it from the facility itself.
Figure 4.3 illustrates the direct-connect pipeline network relative to Avista’s supply
sources and service territories.1

1 Avista has a small amount of pipeline capacity with TransCanada Tuscarora Gas Transmission, a
natural gas transmission pipeline originating at Malin, Oregon, to service a small number of Oregon
customers near the southern border of the state.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 84 of 184
Figure 4.3: Direct-Connect Pipelines

Supply-side resource decisions focus on where to purchase natural gas and how to
deliver it to customers. Each LDC has distinct service territories and geography relative
to supply sources and pipeline infrastructure. Solutions that deliver supply to service
territories among regional LDCs are similar but are rarely generic.
The NWP system is effectively a fully contracted pipeline. Except for La Grande, OR,
Avista’s service territories lie at the end of NWP pipeline laterals. The Spokane, Coeur
d’Alene and Lewiston laterals serve Washington and Idaho load, and the Grants Pass
lateral serves Roseburg and Medford. Capacity expansions of these laterals would be
lengthy and costly endeavors which Avista would likely bear most of the incremental
costs.
The GTN system, also fully contracted, runs from the Kingsgate trading point on the
Idaho-Canadian border down to Malin on the Oregon-California border. This pipeline runs
directly through or near most of Avista’s service territories. Mileage based rates provide
an attractive option for securing incremental resource needs.
Peak day planning aside, both pipelines provide an array of options to flexibly manage
daily operations. The NWP and GTN pipelines directly serve Avista’s two largest service
territories, providing diversification and risk mitigation with respect to supply source, price
and reliability. Northwest Pipeline (NWP) provides direct access to Rockies and British
Columbia supply and facilitates optionality for storage facility management. The Stanfield
interconnect of the two lines is also geographically well situated to Avista’s service
territories.
Roseburg
Medfor
d
SUMAS
ROCKS
Stanfield
NWP GTN
Washington & Idaho
LaGrande
JP
Storage
Malin
Klamath
Falls
AECO
Kingsgate Station 2
Sumas
Rockies
Roseburg &
Medford
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 85 of 184
The rates used in the planning model start with filed rates currently in effect (See
Appendix 4.1 – Current Transportation/Storage Rates and Assumptions). Forecasting
future pipeline rates is challenging. Assumptions for future rate changes are the result of
market information on comparable pipeline projects, prior rate case experience, and
informal discussions with regional pipeline owners. Pipelines will file to recover costs at
rates equal to their cost of service.
NWP and GTN also offer interruptible transportation services. Interruptible transportation
is subject to curtailment when pipeline capacity constraints limit the amount of natural gas
that may be moved. Although the commodity cost per dekatherm transported is generally
the same as firm transportation, there are no demand or reservation charges in these
transportation contracts. Avista does not rely on interruptible capacity to meet peak day
core demand requirements.
Avista's transportation acquisition strategy is to contract for firm transportation to serve
core customers on a peak day in the planning horizon. Since contracts for pipeline
capacity are often lengthy and core customer demand needs can vary over time,
determining the appropriate level of firm transportation is a complex analysis. The
analysis includes the projected number of firm customers and their expected annual and
peak day demand, opportunities for future pipeline or storage expansions, and relative
costs between pipelines and upstream supplies. This analysis is done on semi-annual
basis and through the IRP. Active management of underutilized transportation capacity
either through the capacity release market or engaging in optimization transactions to
recover some transportation costs, keeps Avista’s portfolio flexible while minimizing costs
to customers. Timely analysis is also important to maintain an appropriate time cushion
to allow for required lead times should the need for securing new capacity arise (See
Chapter 6 – Integrated Resource Portfolio for a description of the management of
underutilized pipeline resources).
Avista manages existing resources through optimization to mitigate the costs incurred by
customers until the resource is required to meet demand. The recovery of transportation
costs is often market based with rules governed by the FERC. The management of long-
and short-term resources ensures the goal to meet firm customer demand in a reliable
and cost-effective manner. Unutilized resources like supply, transportation, storage and
capacity can be combined to create products that capture more value than the individual
pieces. Avista has structured long-term arrangements with other utilities that allow
available resources utilization and provide products that no individual component can
satisfy. These products provide more cost recovery of the fixed charges incurred for the
resources. Another strategy to mitigate transportation costs is to participate in the daily
market to assess if unutilized capacity has value. Avista seeks daily opportunities to
purchase natural gas, transport it on existing unutilized capacity, and sell it into a higher
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 86 of 184
priced market to capture the cost of the natural gas purchased and recover some pipeline
charges. The recovery is market dependent and may or may not recover all pipeline costs,
but mitigates pipeline costs to customers.

Storage Resources
Storage is a valuable strategic resource that enables improved management of a highly
seasonal and varied demand profile. Storage benefits include:
• Flexibility to serve peak period needs;
• Access to typically lower cost off-peak supplies;
• Reduced need for higher cost annual firm transportation;
• Improved utilization of existing firm transportation via off-season storage injections;
and
• Additional supply point diversity.

While there are several storage facilities available in the region, Avista’s existing storage
resources consist solely of ownership and leasehold rights at the Jackson Prairie Storage
facility.
Avista optimizes storage as part of its asset management program. This helps to ensure
a controlled cost mechanism is in place to manage the large supply found within the
storage facility. An example of this storage optimization is selling today at a cash price
and buying a forward month contract or selling between different forward months. Since
forward months have risks or premiums built into the price the result is Avista locking in
a given spread. Storage optimization takes place all while maintaining the peak day
deliverability, at a not to exceed level, to plan for this cost-effective resource to serve
customer needs. All optimization of assets directly reduce customers monthly billing.
Jackson Prairie Storage
Avista is one-third owner, with NWP and Puget Sound Energy (PSE), of the Jackson
Prairie Storage Project for the benefit of its core customers in all three states. Jackson
Prairie Storage is an underground reservoir facility located near Chehalis, Washington
approximately 30 miles south of Olympia, Washington. The total working natural gas
capacity of the facility is approximately 25 Bcf. Avista’s current share of this capacity for
core customers is approximately 8.5 Bcf and includes 398,667 Dth of daily deliverability
rights. Besides ownership rights, Avista leased an additional 95,565 Dth of Jackson
Prairie capacity with 2,623 Dth of deliverability from NWP to serve Oregon customers.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 87 of 184
Incremental Supply-Side Resource Options
Avista’s existing portfolio of supply-side resources provides a mix of assets to manage
demand requirements for average and peak day events. Avista monitors the following
potential resource options to meet future requirements in anticipation of changing demand
requirements. When considering or selecting a transportation resource, the appropriate
natural gas supply pairs with the transportation resource and the SENDOUT® model
prices the resources accordingly.
Capacity Release Recall
Pipeline capacity not utilized to serve core customer demand is available to sell to other
parties or optimized through daily or term transactions. Released capacity is generally
marketed through a competitive bidding process and can be on a short-term (month-to-
month) or long-term basis. Avista actively participates in the capacity release market with
short-term and long-term capacity releases. Avista assesses the need to recall capacity
or extend a release of capacity on an on-going basis. The IRP process evaluates if or
when to recall some or all long-term releases.
Existing Available Capacity
In some instances, there is available capacity on existing pipelines. As previously
discussed, both GTN and NWP are fully subscribed, but GTN currently maintains the
ability to flow additional supply from Kingsgate to Spokane as noted in Chapter 7. Avista
has modeled access to the GTN capacity as an option to meet future demand needs in
addition to some capacity in the La Grande area where some quantities are available on
NWP.
GTN Backhauls
The GTN interconnection with the Ruby Pipeline has enabled GTN the physical capability
to provide a limited amount of firm back-haul service from Malin with minor modifications
to their system. Fees for utilizing this service are under the existing Firm Rate Schedule
(FTS-1) and currently include no fuel charges. Additional requests for back-haul service
may require additional facilities and compression (i.e., fuel).
This service can provide an interesting solution for Oregon customers. For example,
Avista can purchase supplies at Malin, Oregon and transport those supplies to Klamath
Falls or Medford. Malin-based natural gas supplies typically include a higher basis
differential to AECO supplies, but are generally less expensive than the cost of forward-
haul transporting traditional supplies south and paying the associated demand charges.
The GTN system is a mileage-based system, so Avista pays only a fraction of the rate if
it is transporting supplies from Malin to Medford and Klamath Falls. The GTN system is
approximately 612 miles long and the distance from Malin to the Medford lateral is only
about 12 miles.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 88 of 184
New Pipeline Transportation
Additional firm pipeline transportation resources are viable and attractive resource
options. However, determining the appropriate level, supply source and associated
pipeline path, costs and timing, and if existing resources will be available at the
appropriate time, make this resource difficult to analyze. Firm pipeline transportation
provides several advantages; it provides the ability to receive firm supplies at the
production basin, it provides for base-load demand, and it can be a low-cost option given
optimization and capacity release opportunities. Pipeline transportation has several
drawbacks, including typically long-dated contract requirements, limited need in the
summer months (many pipelines require annual contracts), and limited availability and/or
inconvenient sizing/timing relative to resource need. No new pipelines were considered
in the current IRP as resource options due to the exceedingly difficult legal path in getting
approval for their construction. If one of these pipeline projects were to come forward as
a viable option Avista would consider the costs and risks in a future IRP.
Pipeline expansions are typically more expensive than existing pipeline capacity and
often require long-term contracts. Even though expansions may be more expensive than
existing capacity, this approach may still provide the best option given that some of the
other options require matching pipeline transportation. Matching pipeline transportation is
creating equivalent volumes on different pipelines from the basin to the delivery point in
order to fully utilize subscribed capacity. Expansions may also provide increased reliability
or access to supply that cannot be obtained through existing pipelines. This is the case
with the Pacific Connector pipeline being proposed as the connecting feedstock for the
Jordan Cove LNG facility in Oregon. The pipeline’s current path connects into Northwest
Pipelines Grants Pass Lateral where capacity is limited. The Pacific Connector pipeline
would add an additional 50,000 Dth/day of capacity along that lateral flowing south from
the Roseburg interconnect.
Several specific projects have been proposed for the region. The following summaries
describe these projects while Figure 4.4 illustrates their location.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 89 of 184
Figure 4.4: Proposed Pipeline Locations

1. Enbridge T-South System Looping
FortisBC and Enbridge are system enhancement on the T-South pipeline.
Removing constraints will allow expansion of Enbridge’s T-South enhanced
service offering, which provides shippers the options of delivering to Sumas or the
Kingsgate market. Expanding the bi-directional Southern Crossing system would
increase capacity at Sumas during peak demand periods. Initial capacity from the
Enbridge system to Kingsgate would increase capacity by 190MMcf/d. This would
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 90 of 184
add incremental gas into the Huntingdon/Sumas market through looping and
compressor station upgrades along the system.
2.FortisBC Southern Crossing Expansion:
The Southern Crossing pipeline system is a bidirectional pipeline connecting
Westcoast T South system at Kingsvale, BC and TransCanada’s Alberta/BC
border. This expansion would include over 90 miles of pipeline looping allowing
access to an additional 300-400 MMcf/d of bi-directional capacity, tying together
station 2 and AECO markets.
3.NWP - Sumas Express
NWP continues to explore options to expand service from Sumas, Wash., to
markets along the Interstate-5 corridor. This project could help relieve the
congestion along this highly populated geographical region in both Washington
and Oregon. Various methods could be used to add this additional capacity
including looping, additional compression and increasing the pipe size and can be
scaled based off demand.
4.TC Energy GTN Trail West
The pipeline taking natural gas off of GTN and onto NWP hub near Molalla is
referred to as Trail West. TransCanada GTN, Northwest Natural and Northwest
Pipeline are the project sponsors of this 106-mile, 30-inch diameter pipeline. The
initial design capacity of this pipeline is 500 MMcf/d and expandable up to 1,000
MMcf/d. This could be an important project if built as it would bring more gas into
the I-5 corridor where unused pipeline capacity is quickly disappearing based on
the demand for natural gas and population increase.
5.TC Energy NGTL and Foothills BC Enhancements
In order to meet existing aggregate demand in southern AB and incremental long-
term delivery commitments at the A/BC border, NGTL is ongoing and expected to
have an in-service date of 2022. This project will increase the delivery point
capacity at the A/BC border by 288,000 GJ per day and will operationally true-up
capacity differences between NGTL and Foothills and provide additional export
capacity into the US.
6.Pacific Connector
Pembina is currently attempting to acquire approval for a 232-mile, 36-inch
diameter pipeline designed to transport up to 1.2 billion cubic feet of natural gas
per day from interconnects near Malin, Oregon, to the Jordan Cove LNG terminal
in Coos Bay, Oregon. The pipeline would deliver the feedstock to the LNG terminal
providing natural gas to international markets, but also to the Pacific Northwest.
The pipeline will connect with Williams’ Northwest Pipeline on the Grants Pass
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 91 of 184
lateral. This ties in directly within Avista’s service territory and will bring in an
additional 50,000 Dth/day of capacity into that area. This new option could provide
Avista’s customers in the area new capacity for growth and supply diversity.

Avista supports proposals that bring supply diversity and reliability to the region. Supply
diversity provides a varied supply base in the procurement of natural gas. Since there are
few options in the Northwest, supply diversity provides options and security when
constraints or high demand are present. Avista engages in discussions and analysis of
the potential impact of each regional proposal from a demand serving and
reliability/supply diversity perspective. In most cases, for Avista to consider them a viable
incremental resource to meet demand needs, it would require combining them with
additional capacity on existing pipeline resources.
In-Ground Storage
In-ground storage provides advantages when natural gas from storage can be delivered
to Avista’s city-gates. It enables deliveries of natural gas to customers during peak cold
weather events. It also facilitates potentially lower-cost supply for customers by capturing
peak/non-peak pricing differentials and potential arbitrage opportunities within individual
months. Although additional storage can be a valuable resource, without deliverability to
Avista’s service territory, this storage cannot be an incremental firm peak serving
resource.
Jackson Prairie
Jackson Prairie is a potential resource for expansion opportunities. Any future storage
expansion capacity does not include transportation and therefore cannot be considered
an incremental peak day resource. However, Avista will continue to look for exchange
and transportation release opportunities that could fully utilize these additional resource
options. When an opportunity presents itself, Avista assesses the financial and reliability
impact to customers. Due to the fast paced growth in the region, and the need for new
resources, a future expansion is possible, though a robust analysis would be required to
determine feasibility. Currently, there are no plans for immediate expansion of Jackson
Prairie.
Other In-Ground Storage
Other regional storage facilities exist and may be cost effective. Additional capacity at
Northwest Natural’s Mist facility, capacity at one of the Alberta area storage facilities,
Questar’s Clay Basin facility in northeast Utah, Ryckman Creek in Uinta County, Wyo.,
and northern California storage are all possibilities. Transportation to and from these
facilities to Avista’s service territories continues to be the largest impediment to these
options. Avista will continue to look for exchange and transportation release opportunities
while monitoring daily metrics of load, transport and market environment.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 92 of 184
LNG Exports
Liquefied natural gas is a process of chilling natural gas to -260 degrees Fahrenheit to
create a condensed version, 1/600 the volume, of natural gas. This process acts as a
virtual pipeline taking domestic production to nearly any location in the world. For years
the U.S. was expected to be an importer of LNG. This is a stark contrast to reality as in
2017 the export of LNG from the U.S. has quadrupled led by two projects, Sabine Pass
in Louisiana and Cove Point in Maryland. In recent history, this market dynamic has
changed from fixed price gas contracts to more spot purchases of LNG. The three largest
countries for U.S. LNG exports are South Korea, Japan and Spain. Waiting in the
wings to provide more LNG supply are four additional export facilities located mostly in
the gulf coast region of the U.S. and will bring the additional demand to nearly 9 Bcf per
day. This massive buildout of LNG exports has led to the U.S. becoming the third largest
exporter of LNG in the world.
LNG and CNG
LNG is another resource option in Avista’s service territories and is suited for meeting
peak day or cold weather events. Satellite LNG uses natural gas that is trucked to the
facilities in liquid form from an offsite liquefaction facility. Alternatively, small-scale
liquefaction and storage may also be an effective resource option if natural gas supply
during non-peak times is sufficient to build adequate inventory for peak events. Permitting
issues notwithstanding, facilities could be located in optimal locations within the
distribution system.
CNG is another resource option for meeting demand peaks and is operationally similar to
LNG. Natural gas could be compressed offsite and delivered to a distribution supply point
or compressed locally at the distribution supply point if sufficient natural gas supply and
power for compression is available during non-peak times.
Estimates for LNG and CNG resources vary because of sizing and location issues. This
IRP uses estimates from other facilities constructed in the area and from conversations
with experts in the industry. Avista will monitor and refine the costs of developing LNG
and CNG resources while considering lead time requirements and environmental issues.
Plymouth LNG
NWP owns and operates an LNG storage facility at Plymouth, Wash., which provides
natural gas liquefaction, storage and vaporization service under its LS-1, LS-2F and LS-
3F tariffs. An example ratio of injection and withdrawal rates show that it can take more
than 200 days to fill to capacity, but only three to five days to empty. As such, the resource
is best suited for needle-peak demands. Incremental transportation capacity to Avista’s
service territories would have to be obtained in order for it to be an effective peaking
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 93 of 184
resource. With available capacity, Plymouth LNG was considered in our supply side
resource modeling but was not selected.
Avista-Owned Liquefaction LNG
Avista could construct a liquefaction LNG facility in the service area. Doing so could use
excess transportation during off-peak periods to fill the facility, avoid tying up
transportation during peak weather events, and it may avoid additional annual pipeline
charges.
Construction would depend on regulatory and environmental approval as well as cost-
effectiveness requirements. Preliminary estimates of the construction, environmental,
right-of-way, legal, operating and maintenance, required lead times, and inventory costs
indicate company-owned LNG facilities have significant development risks. Due to the
changing direction in policy and fossil fuels, Avista did not model this resource in the
current IRP.
Renewable Natural Gas (RNG)
Renewable Natural Gas, or biogas, typically refers to a mixture of gases produced by the
biological breakdown of organic matter in the absence of oxygen. RNG can be produced
by anaerobic digestion or fermentation of biodegradable materials such as woody
biomass, manure or sewage, municipal waste, green waste and energy crops. Depending
on the type of RNG there are different factors to quantify methane saved by its capture
as methane has been found to have a multiplier effect on global warming of 342 times that
of carbon dioxide. Each type of RNG has a different carbon intensity as compared to
natural gas as shown in table 4.2.

2https://www.ipcc.ch/
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 94 of 184
Table 4.2: Carbon Intensity3
Source
Current Carbon
Intensity
(g CO2e/MJ)
Estimated % of Carbon
reduction as compared
to natural gas
lbs. per Dth
Natural Gas 78.37 128.27
Landfill 46.42 41% 75.98
Dairy -276.24 -452% (580.40)
WWT 19.34 75% 31.65
Solid Waste -22.93 -129% (165.80)

RNG is a renewable fuel, so it may qualify for renewable energy subsidies. Once
contained, RNG can be used by boilers for heat, as power generation, compressed
natural gas vehicles for transportation or directly injected into the natural gas grid. The
further down this line greater the need for pipeline quality gas.
Biogas projects are unique, so reliable cost estimates are difficult to obtain. Project
sponsorship has many complex issues, and the more likely participation in such a project
is as a long-term contracted purchaser. Avista considered biogas as a resource in this
planning cycle and depending on the location of the facility it may be cost effective. This
is especially the case when found within Avista’s internal distribution system where
transportation and fuel costs can be avoided. For more information about RNG and its
potential uses in energy policy within Avista territories please see Chapter 5 - Carbon
Reduction.

Avista’s Natural Gas Procurement Plan
Avista’s foundational purpose/goal of the natural gas procurement plan is to provide a
diversified portfolio of reliable supply while at the same time managing the volatility and
cost of that supply. Avista manages the procurement plan by layering in hedges over a
period of time based on average system load per month. Avista does not measure the
success of this plan based on a certain cost or loss risk, rather it is considered successful
when we have secured firm load at a reasonable price while addressing risk inherent
3 California Air Resources Board
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 95 of 184
within these markets. The measurable objectives monitored toward this goal include a
daily financial position of the overall portfolio, tracking of all new and previously transacted
hedges, and the tracking of remaining hedges yet to be purchased based on a percentage
of forecasted load as specified in the procurement plan.
No company can accurately predict future natural gas prices, however, market conditions
and experience help shape Avista’s overall approach to natural gas procurement. The
Avista procurement plan seeks to acquire natural gas supplies while reducing exposure
to short-term price and load volatility. This is done by utilizing a combination of strategies
to reduce the impacts of changing natural gas prices in a volatile market. A portion of
hedges will be focused on the concentration risk of fixed-price natural gas purchases by
utilizing Hedge Windows, and another portion of hedges will target reducing risk in a
volatile market by utilizing Risk Responsive methods. This allows Avista to set a risk level
to help reduce exposure to events outside of our control such as the Energy Crisis in the
early 2000’s or the Enbridge pipeline rupture in 2018 or most recently the COVID-19
pandemic and the oil price collapse.
Hedge transactions may be executed for a period of one-month through thirty-six months
prior to delivery period and are for the Local Distribution Customer (LDC) only. Due to
Avista’s geographic location, transactions may be executed at different supply basins in
order reduce our overall portfolio risk. This procurement plan is disciplined, yet flexible,
allowing for modifications due to changing market conditions, demand, resource
availability, or other opportunities. Should economic or other factors warrant, any material
changes are communicated to senior management and Staff.
In addition to hedges, the Company’s procurement plan includes storage utilization and
daily/monthly index purchases. It is diversified through time, location, and counterparty
in accordance with Risk Management credit terms.
Market-Related Risks and Risk Management
There are several types of risk and approaches to risk management. The 2021 IRP
focuses on two areas of risk: the financial risk of the cost of natural gas to supply
customers will be unreasonably high or volatile, and the physical risk that there may not
be enough natural gas resources (either transportation capacity or the commodity) to
serve core customers.
Avista’s Risk Management Policy describes the policies and procedures associated with
financial and physical risk management. The Risk Management Policy addresses issues
related to management oversight and responsibilities, internal reporting requirements,
documentation and transaction tracking, and credit risk.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 96 of 184
Two internal organizations assist in the establishment, reporting and review of Avista’s
business activities as they relate to management of natural gas business risks:
• The Risk Management Committee includes corporate officers and senior-level
management. The committee establishes the Risk Management Policy and
monitors compliance. They receive regular reports on natural gas activity and meet
regularly to discuss market conditions, hedging activity and other natural gas-
related matters.
• The Strategic Oversight Group coordinates natural gas matters among internal
natural gas-related stakeholders and serves as a reference/sounding board for
strategic decisions, including hedges, made by the Natural Gas Supply
department. Members include representatives from the Gas Supply, Accounting,
Regulatory, Credit, Power Resources, and Risk Management departments. While
the Natural Gas Supply department is responsible for implementing hedge
transactions, the Strategic Oversight Group provides input and advice.

Strategic Initiatives
Strategic Initiatives are generally defined as the means through which a vision is
translated into practice. These initiatives are a group of projects and programs that are
outside of the organizations daily operational activities and help an organization achieve
a targeted performance.
The two primary roles of the Energy Resources Department (including Natural Gas
Supply) is two-fold:
1. Serve Load – Assure adequate and reliable energy supplies for Avista Utilities
natural gas customers.
2. Manage Resources – Exercise prudent stewardship of Avista Utilities energy
supply facilities and related Company resources.
Through the use of fixed-priced hedges, daily balancing transactions and storage
injections and withdrawals the Company can meet its obligation to serve load. In addition,
through our Dynamic Window Hedges and Risk Responsive Hedges, we are also able to
provide a level of price certainty in volatile commodity markets and reduce cost risk
exposure. Related to managing our resources, we have secured firm natural gas
transportation capacity in order to ensure we are able to reliably deliver the commodity to
our customers. Finally, we have secured a level of storage (through ownership at Jackson
Prairie) providing Avista with an additional level of firm supply and associated
transportation contracts.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 97 of 184
It is part of Avista’s culture to be good stewards of our customer’s resources. While there
is no “targeted performance level”, success is measured by the ability to capture benefit
from our existing resources to the best of our ability, which results in either lower overall
expenses for our customers or a higher level of price certainty. As such, we are
continuously monitoring the procurement plan, evolving market conditions, new supply
opportunities, and regulatory conditions.
Accordingly, effective in 2015 the Company implemented a new Storage Optimization
Model which meets the definition of “Strategic Initiative” as described above. Prior to the
implementation of the model, Storage had been utilized in the standard way – to purchase
natural gas in the spring and summer when prices are historically low, inject into Storage,
and withdraw in the winter when prices are historically high. Through the use of this
model, we are able to still provide reliability of supply for our customers, but also capture
benefits of price spreads between time periods. The model is governed by a storage
management program that sets boundaries on injections and withdrawals as well as
tracks real time market data to guide the purchase and sale of natural gas storage
transactions with favorable spreads. Through this model, the Company can purchase
natural gas in one period and sell into a higher priced market, effectively locking in a
benefit for our customers.
The program enforces storage constraints and requirements such as the storage fill
schedule, peak day load requirements, transportation capacity limits, and deliverability
constraints.
The Company also has mechanisms in place which allow us to optimize the value of our
existing pipeline and storage assets in order to reduce costs for customers until such
resources are required to meet demand. Should there be transportation capacity that is
not required to serve load, we may be able to optimize this capacity by purchasing natural
gas, transporting it, and selling it into a higher priced market. Commodity purchases and
sales are carefully tracked and allocated, or directly assigned, jurisdictionally based on
the unique characteristics of each individual pipeline capacity.4 Avista may also be able
to release a portion of this unutilized firm transportation capacity to third parties, further
reducing customer’s firm transportation expense.

4 Allocation between Washington and Idaho for Commodity purchases and sales is based on actual calendar load for each respective month.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 98 of 184
Dynamic Window Hedges (DWH)

The DWH portion of the plan secures a pre-determined, minimum hedge portion for LDC
load with fixed priced purchases. These transactions are diversified in terms of time,
location and delivery period. The target delivery periods, development, procures, and
execution are described below. Dynamic Window Hedging reduces the cost risk and
increases the loss risk.5
The target delivery periods for the DWH portion of the Plan is for a period of 30 to 36
months depending on market availability of the hedging period (Figure 4.5).
Figure 4.5: Dynamic Window Hedging Plan

DWH Development
A DWH is defined by its set-price (SP), an upper control limit (UCL), a lower control limit
(LCL) and an expiration date. The SP is the closing price of the day prior to the window
5 Loss risk is the potential to pay more than the daily gas price with a forward hedge. Cost risk is the potential for daily
prices to rise above the hedge price.
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opening. The UCL and LCL are developed using quantitative mathematics to define
boundaries in relation to the SP. Expiration dates are determined based on the remaining
volumes to be hedged and remaining time to expiration. Each DWH’s SP is based upon
the closing price, of the selected supply basin for the delivery period. The supply basin
for each hedge window will be selected from available term markets, based on whichever
market has the highest volatility.
Hedge windows remain “open” as long as the previous day’s forward delivery period price
remains between the UCL and the LCL, and the window has not reached its time
expiration. The selected basin closing price will be the determining benchmark of the
forward delivery period price. Hedge window status is examined each business day. If
the hedge window’s current rate moved outside the UCL or LCL, a hedge transaction is
triggered, subject to execution provisions described later in this report. If a SP does not
move outside the UCL or LCL prior to time expiration, then the window’s hedge
transaction is executed on the expiration date.
Figure 4.6 shows a hedge which was executed for the Summer of 2022 (April – October)
time period and the associated limits.
Figure 4.6: Dynamic Window Hedge (April 2022 – October 2022)

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Risk Responsive Hedging Tool (RRHT)
In 2018, Gas Supply incorporated a Risk Responsive Hedging Tool in addition to the
Dynamic Window Hedges discussed above. The RRHT helps to manage the Value at
Risk (VaR) of Avista’s LDC natural gas portfolio’s open position on a daily basis. The
forward gas prices are the basis for the VaR analysis. The analysis utilizes a confidence
level and historic volatility to calculate a portfolio VaR, and combines it with the current
mark-to-market portfolio price to develop a price risk metric that is compared to a
predetermined threshold value (Operative Boundary). If the price metric exceeds the
Operative Boundary, then one or more hedges will be executed to bring the price metric
back within the Operative Boundary. In any case, hedge volumes should not exceed the
Maximum Hedge Ratio. Upon trigger, Gas Supply will begin to transact to bring the price
metric back within the Operative Boundary.
The Dynamic Window Hedging will continue to systematically hedge to a certain minimum
hedge level through the use of time limits and UCL/LCL. RRHT will monitor the market
financially and call for additional hedging if pre-determined risk tolerance limits are
triggered.
The RRHT includes all utility purchase and sales transactions, estimated customer load,
and storage injections and withdrawals to derive open positions (by basin) that are
marked to forward market prices. These monthly financial positions, along with market
volatility, are then used to calculate the Value at Risk (VaR) by basin, which in turn is
used to evaluate recommended hedging actions.

Supply Issues
The abundance and accessibility of shale gas has fundamentally altered North American
natural gas supply and the outlook for future natural gas prices. Even though the supply
is available and the technology exists to access it, there are issues that can affect the
cost and availability of natural gas.
Hydraulic Fracturing
Hydraulic fracturing (commonly referred to as fracking) was invented by Hubbert and
Willis of Standard Oil and Gas Corporation back in the late 1940’s. The process involves
a technique to fracture shale rock with a pressurized liquid. In the past 15 years, the
techniques and materials used have become increasingly perfected opening up large
deposits of shale gas formations at a low prices. The Energy Information Administration
(EIA) tracks production per well in the seven key oil and natural gas production formations
in the United States as shown in Figure 4.7. Figure 4.8 shows the continued increase in
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efficiency of production compared to just a year ago as shown by the EIA’s Drilling
Productivity Report 4.96.
Figure 4.7: Seven Major Drilling Regions in the United States

Figure 4.8: December 2020 Drilling Productivity Report, EIA7

With the increasingly prevalent use of hydraulic fracturing came concerns of chemicals
used in the process. The publicity caused by movies, documentaries and articles in
6 Drilling Productivity Report, https://www.eia.gov/petroleum/drilling/pdf/summary.pdf
7 www.eia.gov
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national newspapers about “fracking” has plagued the natural gas and oil industry. There
is concern that hydraulic fracturing is contaminating aquifers, increasing air pollution and
causing earthquakes. The actual cause of earthquakes is wastewater injection used in
operations at the well site. Based on research at the U.S. Geological Survey, only a small
number of these earthquakes are from fracking itself.8 Additionally, wastewater injections
are used for all well types, not just those where fracking is involved.
The wide-spread publicity generated interest in the production process and caused some
states to issue bans or moratoriums on drilling until further research was conducted. To
help combat these fears, Frac Focus9 was created and is a chemical disclosure registry
allowing users to view chemicals used by over 125,000 wells throughout North America.
This information, voluntarily submitted by Exploration and production companies,
provides a detailed list of materials used to frack each individual well.
Pipeline Availability
The Pacific Northwest has efficiently utilized its relatively sparse network of pipeline
infrastructure to meet the region’s needs. As the amount of renewable energy increases,
future demand for natural gas-fired generation will increase. Pipeline capacity is the link
between natural gas and power.
There are currently a few industrial plants being considered in the Pacific Northwest. The
project with the highest likelihood is the project located in Washington’s Port of Kalama.
This process uses large amounts of natural gas as a feedstock for creating methanol,
which is used to make other chemicals and as a fuel. At over 300,000 Dth per day this
plant would consume large amounts of natural gas.

Ongoing Activity
Without resource deficiencies or a need to acquire incremental supply-side resources to
meet peak day demands over the next 20 years, Avista will focus on normal activities in
the near term, including:
• Continue to monitor supply resource trends including the availability and price of
natural gas to the region, LNG exports, supply dynamics and marketplace, and
pipeline and storage infrastructure availability.
8 https://profile.usgs.gov/myscience/upload_folder/ci2015Jun1012005755600Induced_EQs_Review.pdf
9 https://fracfocus.org/
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• Monitor availability of resource options and assess new resource lead-time
requirements relative to resource need to preserve flexibility.
• Appropriate management of existing resources including optimizing underutilized
resources to help reduce costs to customers.
• Monitor renewable supply resource options, availability and pricing trends.

Conclusion
North American fossil natural gas supply continues to show its robustness in spite of
challenges it faces. Regional supply constraints are beginning to increase in their
likelihood causing prices to act in a more volatile fashion. This volatility in pricing paired
with supply side resource availability has made Avista’s procurement plan an increasingly
important piece to manage customer rates, diversity of supply and peak day demand.
Without new supply side resources, the region will face some difficult decisions in the
coming decades. This in combination with the optimization of our storage, transportation
and basin resources have helped Avista to provide natural gas reliably to our customers
at a fair and reasonable price.
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5: Carbon Reduction
Regulatory environments regarding energy topics such as renewable energy, carbon
reduction, carbon intensity and greenhouse gas regulation continue to evolve since
publication of the last IRP. Current and proposed regulations by federal and state
agencies, coupled with political and legal efforts, have implications for the reduction of
carbon in the natural gas stream.
Avista and Carbon Reduction:
Focus on solutions that balance carbon reduction, affordability, and reliability.

Avista’s Environmental Objective
Avista has always been on the forefront of clean energy and innovation. Founded on
clean, renewable hydro power on the banks of the Spokane River, Avista has maintained
a generation portfolio that is already more than half renewable, while continuously making
investments in new renewable energy, advancing the efficient use of electricity and
natural gas, and driving technology innovation that has enabled and will continue to
become the platform and gateway to a clean energy future.

Environmental Issues
The evolving and sometimes contradictory nature of environmental regulation from state
and federal perspectives creates challenges for resource planning. The IRP cannot add
renewables or reduce emissions in isolation from topics such as system reliability, least
cost requirements, price mitigation, financial risk management, and meeting changing
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environmental requirements. All resource choices have costs and benefits requiring
careful consideration of the utility and customer needs being fulfilled, their location, and
the regulatory and policy environment at the time of procurement.

Natural Gas System Emissions
Upstream emissions include any emission found upstream of the point of combustion and
includes production, processing, transmission and equipment. To fully account for
emissions in the natural gas stream the upstream emissions are now included in the totals
as measured in pounds of carbon dioxide equivalent. This becomes important when
placing a tax or cost of emissions on the price per Mmbtu. The emissions are measured
at the standard 100-year Global Warming Potential (GWP) meaning a 34 multiplier of the
heat that would be absorbed by the same mass of carbon dioxide. The levels of upstream
gas are determined by production region, specifically in Canada and the Rockies in the
United States and multiplied by the associated emissions estimate. Over the past five
years, nearly 90 percent of Avista’s natural gas was sourced from Canadian production
leaving roughly 10 percent of estimated upstream emissions to the Rockies region. When
combined with a 0.77 percent of Canadian production attributed to upstream emissions,
as calculated in a study for the Tacoma LNG project, the majority of Avista’s fossil fuel
natural gas is less intensive as compared to the fossil natural gas emissions from the
Rockies region of 1.0 percent as calculated in the EIA sinks and emissions estimates.
This estimate1 from the EIA is updated on a yearly basis and will show gains and losses
as they occur as compared to a point in time study.
The final upstream emissions from CH4 in carbon equivalent add nearly 10.66 pounds
per MMBtu as shown in Table 5.1:
Table 5.1: Avista Specific LDC Natural Gas Emissions
Avista Specific Natural Gas
Combustion Lbs. GHG/MMBtu Lbs. CO2e/MMBtu
CO2 116.88 116.88
CH4 0.0022 0.0748
N2O 0.0022 0.6556
Total Combustion 117.61
Upstream
CH4 0.313406851 10.66
Total 128.27

At a national level, overall methane emissions in the U.S. have been on the decline for
many decades. As illustrated in Figure 5.1, the EPA has estimated methane emissions
as decreasing by nearly 20 percent as compared to 1990. As coal fired plants have
1 Inventory of U.S. Greenhouse Gas Emissions and Sinks | Greenhouse Gas (GHG) Emissions | US EPA
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retired, production of electricity natural gas generation has dramatically increased to
cover this demand. Interestingly, during this reference period, production from natural gas
has more than doubled while total electric production increased 35 percent during this
same timeframe.
Figure 5.1: United States Methane Emissions

Carbon dioxide equivalent (CO2e) is the most common unit to measure climate warming.
In order to understand how different greenhouse gasses such as methane (CH4) and
nitrous oxide (N20) affect the earths warming a conversion must occur. As illustrated in
Table 5.2 below, the Intergovernmental Panel on Climate Change released their 5th
assessment study to help define these impacts to global warming in units of CO2e.
Table 5.2: Global Warming Potential (GWP) in CO2 Equivalent
5th Assessment of the Intergovernmental Panel on Climate Change
Greenhouse Gas GWP – 100 Year GWP – 20 Year
CO2 1 1
CH4 34 86
N2O 298 268

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Local Distribution Pipeline Emissions - Methane Study
In a study led by Washington State University (WSU), and sponsored by the
Environmental Defense Fund (EDF) and others, an estimate of utility pipeline distribution
systems leakage found that overall levels of leakage were around 0.1 percent to 0.2
percent of methane delivered nationwide. The study goes on to state that the Eastern
regions of the United States contribute much more methane to the total, as compared to
the Western regions, which were found to account for only 5 percent of these emissions
overall. The study theorizes that older infrastructure and material types are the likely
culprit, but also goes on to attribute regulations and better infrastructure and monitoring
by utilities for these decreased emissions. It found that “out of 230 measurements, three
large leaks accounted for 50 percent of the total measured emissions from pipelines
leaks. In these types of emission studies, a few leaks accounting for a large fraction of
total emissions are not unusual.”2
State and Regional Level Policy Considerations
The lack of a comprehensive federal greenhouse gas policy encouraged states, such as
California, to develop their own climate change laws and regulations. Climate change
legislation takes many forms, including economy-wide regulation under a cap and trade
system, a cap and reduce system, and a carbon tax. Comprehensive climate change
policy can include multiple components, such as renewable portfolio standards, DSM
standards, and emission performance standards. Individual state actions produce a
patchwork of competing rules and regulations for utilities to follow and may be particularly
problematic for multi-jurisdictional utilities such as Avista.

Idaho
Idaho Policy Considerations
Idaho does not regulate greenhouse gases. There is no indication Idaho is moving toward
regulation of greenhouse gas emissions beyond federal regulations.

Oregon
Oregon Policy Considerations
The State of Oregon has a history of greenhouse gas emissions and renewable portfolio
standards legislation. In March of 2020, Governor Brown signed into law Executive Order
(EO) 20-04 requiring the reduction of greenhouse gas emissions to at least 45 percent
below 1990 levels by 2035 and 80 percent below 1990 levels by 2050. This EO requires
the reductions statewide by all carbon emitting sources and managed by the respective
emissions sources governing agencies. State agencies are directed to exercise any and
all authority to achieve GHG emissions reduction goals expeditiously. Many specifics of
2 https://methane.wsu.edu
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this EO will be taking shape in the upcoming year including systems, carbon costs,
programs such as to a cap and reduce program to buy or sell offsets and many other
complexities of an endeavor of this magnitude.
Oregon SB 334
In Oregon, Senate Bill 3343 was passed in to help develop, update, and maintain the
biogas inventory available. This includes the sites and potential production quantities
available in addition to the quantity of renewable natural gas available for use to reduce
greenhouse gas emissions. This bill will also help promote RNG and identify the barriers
and removal of barriers to develop and utilize RNG. In September 2018 the Oregon
Department of Energy issued the report to the Oregon legislature titled “Biogas and
Renewable Natural Gas Inventory.”
Oregon SB 844
Senate bill 844 passed in 2013 with rulemaking following under AR 580, placed into effect
in December of 2014. This bill directed the OPUC to establish a voluntary emission
reduction program and criteria for the purpose of incentivizing public natural gas utilities
to invest in emission reducing projects providing benefits to their respective customers.
The public utility, without the emission reduction program, would not invest in the project
in the ordinary course of business.
To date, this legislation has not yielded any emission reducing projects. Avista is aware
that Governor Brown’s Executive Order 20-04 has the OPUC reconsidering the
usefulness of SB844.
Oregon SB 98 & AR 632 Rule Making
Oregon Senate Bill 98 passed during the 2019 regular session and mandates the Oregon
Public Utility Commission (PUC) “to adopt by rule a renewable natural gas program for
natural gas utilities to recover prudently incurred qualified investments in meeting certain
targets for including renewable natural gas purchases for distribution to retail natural gas
customers.”
The Oregon PUC initiated the AR 632 rulemaking process in late 2019 with a series of
public workshops. This collaborative process with various stakeholder involvement and
input concluded in the spring of 2020. Final rules were made effective on July 17, 2020.
The rule allows investment recovery. In order to participate in Oregon’s SB 98 RNG
Program, a petition to participate is required. Small utilities desiring to participate are
required to define their respective percent of revenue requirement per year needed to
support potential project investment costs. The bill allows investment in gas conditioning
equipment without RFP process. Per AR 632 the RNG attributes will be tracked by the
3 https://olis.leg.state.or.us/liz/2017R1/Downloads/MeasureDocument/SB334
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M-RETS system as renewable thermal certificates (RTC) in which (1) RTC = (1)
Dekatherm of RNG.

Washington
Washington State Policy Considerations4
In December 2020 a State Energy Strategy was released as a roadmap that commits
Washington to reducing greenhouse gas emissions:
• By 2030 a 45% reduction below 1990 levels
• By 2040 a 70% reduction below 1990 levels
• By 2050 a 95% reduction below 1990 levels and net-zero emissions
Washington HB 2580
Washington State House Bill 25805 was signed by Governor Jay Inslee on March 22,
2018 and will become effective on July 1, 2018 bringing into law a bill to help encourage
production of renewable natural gas (RNG). This bill requires the Washington State
University Extension Energy Program and the Department of Commerce (DOC) along
with the consulting of the Washington State Utilities and Transportation Commission, to
submit recommendations on promoting the sustainable development of RNG. The DOC
will consult with natural gas utilities and other state agencies to explore developing
voluntary gas quality standards for the injection of RNG into natural gas pipeline systems
in the state.
Washington HB 1257
The bill passed during the 2019 Regular Session, coined the “Building Energy Efficiency”
bill, mandates that each gas company must offer by tariff a voluntary renewable natural
gas service. The bill also allows for LDCs to create an RNG program to supply a portion
of the natural gas to customers. This program is subject to review and approval by the
UTC. With regard to natural gas distribution companies, this bill was designed for the
purpose of establishing “efficiency performance requirements for natural gas distribution
companies, recognizing the significant contribution of natural gas to the state’s
greenhouse gas emissions, the role that natural gas plays in heating buildings and
powering equipment within buildings across the state, and the greenhouse gas reduction
benefits associated with substituting renewable natural gas for fossil fuels.”
Section 12 of the bill “finds and declares that:
4 2021 State Energy Strategy - Washington State Department of Commerce
5 http://apps2.leg.wa.gov/billsummary?Year=2017&BillNumber=2580&Year=2017&BillNumber=2580
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a)Renewable natural gas provides benefits to natural gas utility customers and to
the public;
b)The development of RNG resources should be encouraged to support a smooth
transition to a low carbon energy economy in Washington;
c)It is the policy of the state to provide clear and reliable guidelines for gas
companies that opt to supply RNG resources to serve their customers and that
ensure robust ratepayer protections.”
Section 13 of the bill allows LDC’s to propose an RNG program under which the company
would supply RNG for a portion of the natural gas sold or delivered to its retail customers.
Section 14 of the bill states that LDC’s must offer by tariff a voluntary RNG service
available to all customers to replace any portions of the natural gas that would otherwise
be provided by the gas company.
HB 1257 provided limited direction and the necessary details to advance RNG programs
and projects. As such, there has been an effort on behalf of the impacted utilities to
provide the commission with feedback and clarity with respect to gas quality and cost
treatment. More specifically, the Northwest Gas Association (NWGA) has collaborated
with Washington LDC’s to develop a common Gas Quality Standard Framework, and
proposed language defining the treatment of RNG program costs.
On December 16, 2020, the Washington UTC issued a Policy Statement to provide
guidance with respect to the following elements of HB 1257 as follows; General Program
Design, RNG Program cost cap, Voluntary Program cost treatment, gas quality
standards, and pipeline safety, environmental attributes and carbon intensity, renewable
thermal credit (RTC) tracking, banking and verification.
RNG at Avista
Avista has been preparing for RNG. A new RNG Program, RNG Manager, and a cross-
functional working team has been assembled and includes representatives from Gas
Engineering, Gas Supply, Legal, Governmental Affairs, Regulatory Affairs, Products &
Services, Business Development & Strategy, Corporate Communications, and
Environmental. This team meets on a routine basis for program and project updates and
coordination purposes. Additionally, internal efforts to prepare for and advance RNG
include but are not limited to; draft charter document, draft business cases for use in
Capital Budget Planning process, internal communications, gas quality, interconnection
requirements, and business development efforts in pursuit of potential RNG projects.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Program Considerations
As Avista prepares to move forward with RNG, some of the primary considerations given
are as follows:
•Evaluate available RNG procurement options
•Pursue potential RNG development opportunities from local RNG feedstock
resources under new legislation (Washington HB 1257 & Oregon SB 98)
•Develop an understanding of RNG development cost, cost recovery impacts to
customers, resulting supply volumes and RNG costs
•Evaluate potential RNG customer market demands vs. supply
•Participation in rule making and policy:
•Participation in HB 1257 Policy development
•Participation in SB 98 Policy Rulemaking via AR 632 informal and formal
•Cost recovery proposal led by NWGA with input from all four Washington LDC’s
•Collaborative RNG Gas Quality Framework established across four Washington
LDC’s
Pipeline Safety & Interconnection Requirements
Avista’s Gas Engineering Department has researched and learned about gas quality,
testing, and interconnection requirements from those at the forefront of the RNG industry.
Additionally, through a collaborative effort coordinated by the Northwest West Gas
Association (NWGA), all four Washington LDC’s have developed a common Gas Quality
Framework which is now that basis for Avista’s Gas Quality Specification. The
development of Interconnection requirements and draft contractual language has also
been developed and has taken form as an Interconnection Agreement template. Other
procedural documents such as an Interconnection Study Agreement and RNG
Interconnection Request Form have been developed.
RNG workshops and rulemaking
In addition to participating in RNG industry workshops and conferences to learn how
others are implementing RNG projects and programs, Avista has actively participated in
Oregon SB 98 informal and formal rulemaking, and Washington HB 1257 workshops
including collaborative efforts with the NWGA to develop a common Gas Quality
Framework, and proposed cost cap language.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Utility RNG Projects
RNG projects require feedstocks that are not always readily available and feedstock
owners who are willing to partner with an LDC. Even with potential willing feedstock
partners, Avista recognizes many practical complexities associated with developing RNG
projects as well as the many benefits. The following examples are based on what we
have learned during our business development efforts;
• New legislation allows LDC’s to invest in RNG infrastructure projects with
feedstock partners
• LDC’s are credit worthy partners offering long term off-take contracts to feedstock
owners
• Each RNG project is unique with respect to capital development costs & resulting
RNG costs
• Each RNG project will vary in size, location, and distance to interconnection
pipeline, feedstock type, gas conditioning equipment and requirements, and
operating costs
• Economies of scale – Low volume biogas opportunities face economic challenges
• The utility cost of service model is typically a foreign concept to feedstock owners,
requiring an educational process to get them comfortable
• Feedstock owners over-valuing their biogas can degrade project economics
• New RNG Projects can take 3-4 years to develop given myriad factors. A new
RNG project is a multi-year endeavor involving the usual phases expected for
major capital construction projects, coupled with many first ever discussions
between the utility and the feedstock owner, a new regulatory process and
program requirements, the identification of customer cost impacts, environmental
benefits, and tracking process just to name a few
• Customers have paid for a vast pipeline infrastructure that can be utilized for a
cleaner future by transitioning the fuel and keeping the pipe

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Project Evaluation - Build or Buy
Avista recognizes the two primary options to procure RNG; build RNG project(s) or buy
RNG. In the build scenario, new RNG facilities are developed, and the costs are
recovered the through AAC or GRC. Avista can also buy RNG from other RNG producers
and pass the costs through the GPA.
Build
Both Oregon SB 98 and Washington HB 1257 are both focused on decarbonization for
the greater good of society and both pieces of legislation clearly support the development
of new RNG infrastructure and RNG resources by allowing utility companies (LDC’s) to
build and deliver RNG on a utility cost-of-service model for utility customer building heat
usage. Both allow the recovery of investments through an AAC or GRC. Avista believes
the “build” option best meets the intent of the legislation as it affords a higher level of cost
control through the elimination of for-profit intermediary burdens, delivering RNG to
customers at the true cost. Further, local projects contribute to improved local air quality,
and support the local economy during construction and during annual operations.
Naturally, feedstock biogas royalties are expected to be a key factor in project economics,
as will operating costs including power, conditioning equipment type, interconnection
pipeline distance and cost. Since utility companies are institutional credit worthy partners
that can offer long term off-take contracts for biogas, it is expected that these types of
arrangements will be desirable with feedstock owners, and that long-term arrangements
will temper biogas royalty pricing. Ultimately the utility customer benefits from this
scenario.
Buy
The new legislation in Oregon and Washington is an intentional shift away from the
transportation market and opens the door for a new renewable thermal credit (RTC)
market which is not intended to compete with the existing heavily subsidized
transportation markets, federal and state alike. In the short term, and since the
transportation and utility markets are in conflict with respect to RNG values, the
procurement of RNG for utility use is an inherent challenge for utility use.
At Avista, we expect our voluntary RNG program demands to be limited volumes, and
short-term in nature in the initial years. Since a short-term, low-volume off-take purchase
scenario is not likely to be attractive to producers that typically seek long-term off-take
agreements, the expectation is higher RNG costs. Given the nature of this temporary
interim situation, a short-term voluntary pilot program in which off-take volumes may be
procured from a local producer with excess supply, at a negotiated price may be
advantageous.

This strategy will allow Avista to ramp-up and learn more about our new first ever
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voluntary RNG program and minimize risk until at a point in time in which Avista can
supply RNG from new RNG infrastructure investment projects.
Voluntary RNG Programs
Avista’s Products and Services Department will be developing Avista’s first ever voluntary
RNG product. To date the following market studies and observations have been
completed:
• RNG Commercial Market Study completed in 2019
• RNG Residential Market Survey concluded in September 2020
• Customers lack understanding of RNG since it is a new concept
• Customers like the environmental aspects of RNG
• Customers like to choose their level of participation to manage costs predictably
The voluntary customer RNG program design will advance based on the studies above.
Estimated voluntary customer program demands are yet to be defined, however volumes
are expected to be very small initially. Eventually, Avista is looking forward to adding RNG
to Avista’s renewables portfolio.
Cost Effective Evaluation Methodology
At Avista, developing a methodology has been a work in process. To date, the
methodology shown is derived from OPUC UM2030, also referenced in the OPUC SB 98
AR 632 Rulemaking. The evaluation method shown herein is subject to input, refinement
and reconsideration (Figure 5.2).

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Figure 5.2: Avista Renewable Resource Development and Procurement Decision
Tree – Part 16

6 The Avista Renewable Resource Development and Procurement Decision Tree described above is a
work in progress and is subject to change at any time.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Figure 5.3: Avista Renewable Resource Development and Procurement Decision
Tree – Part 2

In-depth descriptions of the calculations and components used in the Avista Renewable
Resource Development and Procurement Decision Tree are in Appendix 5.
Environmental Attribute Tracking
Oregon SB 98 specifies M-RETS as the third-party entity designated to manage
environmental attribute tracking and banking. M-RETS will utilize a proprietary
transparent electronic certificate tracking system in which (1) renewable thermal
certificate (RTC) is equal to (1) dekatherm (Dth) of RNG per the OPUC.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Given the Oregon requirement, and in lieu of contracting with another vendor for the
tracking and banking of Washington environmental attributes, Avista will likely use M-
RETS for Washington RNG attributes.
The California RNG market will continue to be a major draw for renewable resources due
to the low carbon fuel standard (LCFS) in addition to the federal RIN market. These
incentives can bring the value of these specific renewable resource attributes to many
multiples of conventional natural gas prices. While the market has volatility based on
demand, the primary issue of bringing additional projects into the market are based on
the unknowns as related to the market itself. There are currently no forward prices for
these renewable credits and the environmental attribute value for local markets is
unidentified. These are just a few of the major obstacles potential producers run into
when looking for financing of their projects.
A potential solution to some of these unknowns in the market are through utility RNG
projects. These feedstock owners would now be able to partner with LDC’s to cultivate
new RNG projects. The obstacle of financing becomes less of an issue as most LDC’s
are credit worthy and can provide a measure of certainty with long term offtake
agreements. This concept would test the project owner’s willingness to partner with the
utility’s cost of service model, which is a foreign concept when seeking the highest value
for their biogas.
Developing a generic cost for RNG based on feedstock will require several assumptions
as each specific RNG project will have its own capital development costs. Each RNG
project will vary in size, location and distance to interconnection pipeline, feedstock type,
gas conditioning equipment and requirements and operating costs. In general terms, new
RNG projects can take 2-3 years to develop depending on size and scope.
Hydrogen
Hydrogen is a fuel source with a long history and a great potential to help solve f uture
energy needs. Its energy factor, as measured in a kilogram (kg) of low heating value
(LHV), is roughly equivalent to a gallon of gasoline. While hydrogen can be made from
any energy source including nuclear (pink H2) and electric renewables (green H2), most
is currently made by reforming natural gas, also known as grey H2. The high cost of this
energy has been the primary barrier to an accelerated use and adoption. With expanding
renewable electricity production, the ability to create green H2 with ex cess renewable
electricity is moving from concept to market throughout the world. While it is assumed
hydrogen can only be mixed and stored in a natural gas distribution pipeline system as a
small percentage of the total volume of gas in the pipe, it can be combined with a carbon
dioxide source first to produce methane, referred to as methanation, and then injected in
a natural gas pipe without limits on the percent in the gas stream. This process of using
power to separate water into hydrogen and oxygen is known as power to gas. This
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 118 of 184
process can provide seasonal energy storage needs while providing a useful product
based on when renewable electricity is being produced.

Conclusion
Avista views RNG and low carbon fuels as an important component of its corporate
environmental strategy and decarbonization goals. By utilizing waste streams to create
green fuel, RNG and H2 both support Avista’s environmental strategy and will provide
Avista’s customers with a new environmentally friendly, low carbon fuel choice, delivered
seamlessly via Avista’s existing natural gas system.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 119 of 184

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 120 of 184
6: Integrated Resource Portfolio
Overview
This chapter combines the previously discussed IRP components and the model used to
determine resource deficiencies during the 20-year planning horizon. This chapter
provides an analysis of potential resource options to meet resource deficiencies as
exhibited in the High Growth, Low Prices scenario and the Carbon Reduction scenario.
The foundation for integrated resource planning is the criteria used for developing
demand forecasts. The weather planning standard has been updated in the current IRP
cycle. The new planning standard has Avista moving away from coldest on record and
into a 99 percent probability of a daily temperature occurring. Avista plans to serve
expected peak day in each demand region with firm resources. Firm resources include
natural gas supplies, firm pipeline transportation and storage resources. In addition to
peak requirements, Avista also plans for non-peak periods such as winter, shoulder
months (April and October) and summer demand. The modeling process includes an
optimization for every day of the 20-year planning period.
It is assumed that on a peak day all interruptible customers have left the system to provide
service to firm customers. Avista does not make firm commitments to serve interruptible
customers, so IRP analysis of demand-serving capabilities only includes the firm
residential, commercial and industrial classes. Using the weather planning standard, a
blended price curve of three studies developed by industry experts, and an academically
backed customer forecast all work together to develop stringent planning criteria.
Forecasted demand represents the amount of natural gas supply needed. In order to
deliver the forecasted demand, the supply forecast needs to increase between 1.0
percent and 3.0 percent on both an annual and peak-day basis to account for additional
supplies purchased primarily for pipeline compressor station fuel. The range of 1.0
percent to 3.0 percent, known as fuel, varies depending on the pipeline. This fuel is used
to move the gas from point A on the pipeline to point B or the delivery point. The FERC
and National Energy Board approved tariffs govern the percentage of required additional
fuel supply.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 121 of 184
SENDOUT® Planning Model
SENDOUT® is a linear programming model used to solve natural gas supply and
transportation optimization questions. Linear programming is a proven technique to solve
minimization/maximization problems. SENDOUT® analyzes the complete problem at one
time within the study horizon, while accounting for physical limitations and contractual
constraints.
The software analyzes thousands of variables and evaluates possible solutions to
generate a least cost solution given a set of constraints. The model considers the
following variables:
• Demand data, such as customer count forecasts and demand
coefficients by customer type (e.g., residential, commercial and
industrial).
• Weather data, including minimum, maximum and average
temperatures.
• Existing and potential transportation data which describes the network
for physical movement of natural gas and associated pipeline costs.
• Existing and potential supply options including supply basins, revenue
requirements as the key cost metric for all asset additions and prices.
• Natural gas storage options with injection/withdrawal rates, capacities
and costs.
• Conservation potential.

Figure 6.1 is a SENDOUT® network diagram of Avista’s demand centers and resources.
This diagram illustrates current transportation and storage assets, flow paths and
constraint points.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 122 of 184
Figure 6.1 SENDOUT® Model Diagram

The SENDOUT® model provides a flexible tool to analyze scenarios such as:
• Pipeline capacity needs and capacity releases;
• Effects of different weather patterns upon demand;
• Effects of natural gas price increases upon total natural gas costs;
• Storage optimization studies;
• Resource mix analysis for conservation;
• Weather pattern testing and analysis;
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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• Transportation cost analysis;
• Avoided cost calculations; and
• Short-term planning comparisons.

SENDOUT® also includes Monte Carlo capabilities, which facilitates price and demand
uncertainty modeling and detailed portfolio optimization techniques to produce probability
distributions. More information and analytical results are located in Chapter 7 – Alternate
Scenarios, Portfolios and Stochastic Analysis. The SENDOUT® model is used by LDC’s
across the U.S., however it is becoming increasingly outdated for the current regulatory
environment when it comes to carbon reduction. Because of this enhanced need for
modeling software, Avista is planning on replacing SENDOUT® as stated in Chapter 9 –
Action Plan.

Resource Integration
The following sections summarize the comprehensive analysis bringing demand
forecasting and existing and potential supply and demand-side resources together to form
the 20-year, least-cost plan. Chapter 2 - Demand Forecasts describes Avista’s demand
forecasting approach.
Avista forecasts demand in the SENDOUT® model in eleven service areas given the
existence of distinct weather and demand patterns for each area and pipeline
infrastructure dynamics. The SENDOUT® areas are Washington and Idaho (each state
is disaggregated into three sub-areas because of pipeline flow limitations and the ability
to physically deliver gas to an area); Medford (disaggregated into two sub-areas because
of pipeline flow limitations); and Roseburg, Klamath Falls and La Grande. In addition to
area distinction, Avista also models demand by customer class within each area. The
relevant firm customer classes are residential, commercial and industrial customers.
Customer demand is highly weather-sensitive. Avista’s customer demand is not only
highly seasonable, but also highly variable. Figure 6.2 captures this variability showing
monthly system-wide average demand, minimum demand day observed by month,
maximum demand day observed in each month, and winter projected peak day demand
for the first year of the Expected Case forecast as determined in SENDOUT®.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 124 of 184
Figure 6.2: Total System Average Daily Load (Average, Minimum and Maximum)

Natural Gas Price Forecasts
Natural gas prices play an integral role in the development of the IRP. It is the most
significant variable in determining the cost-effectiveness of DSM measures and of
procuring new resources. The price of natural gas also influences consumption through
price elasticity, which affects demand in Avista’s natural gas service territories.
The natural gas price outlook has changed dramatically in recent years in response to
several influential events and trends affecting the industry, including improved drilling
methods and technology used in oil and natural gas production, increasing exports to
Mexico, and LNG. These factors, in addition to more stringent renewable energy
standards and increased need for natural gas-fired generation to back up such resources,
are contributing to the rapidly changing natural gas environment. The uncertainty in
predicting future events and trends requires modeling a range of forecasts.
Many additional factors influence natural gas pricing and volatility, such as regional supply
and demand issues, weather conditions, storage levels, natural gas-fired generation,
infrastructure disruptions, and infrastructure additions, such as new pipelines and LNG
terminals. Estimates of these supply resource additions vary between studies as does the
study date and ultimately drive the primary differences between sources in pricing
expectations.
-
50,000
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300,000
350,000
400,000
Dt
h

/

D
a
y
Average Load Max Load Min Load Peak Day
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Although Avista closely monitors these factors, we cannot accurately predict future prices
across the 20-year horizon of this IRP. As a result, several price forecasts from credible
industry experts were used in developing the price forecasts considered in this IRP.
Figure 6.3 depicts the annual average prices of these forecasts in nominal dollars and
includes the expected price resulting from a blending technique.
Figure 6.3: Henry Hub Forecasted Price (Nominal $/Dth)

Expected prices at Henry Hub were derived through a blend of forecasts from four
sources, including the New York Mercantile Exchange (NYMEX) forward strip on June
30, 2020, the Energy Information Administration’s (EIA) 2020 Annual Energy Outlook
(AEO), and two reputable market consultants. Combining an ensemble of forecasts
improves the accuracy of our model based on the premise that the aggregate market
knows more than any single entity or model.
The weightings applied to each source vary throughout the twenty-year forecasting
horizon. Due to the high volume of market transactions, expected prices align completely
with those of the NYMEX forward strip in the first two years. From 2023 through 2025,
market activity and speculation on the NYMEX deteriorate significantly, so forecasts from
the other three sources, proportionally, are applied incrementally more weighting. By the
year 2026, and through the end of our forecasting horizon, the expected price is the result
of an equally weighted blend of forecasts from the EIA’s AEO and our two market
consultants. The specific weightings applied are described in Table 6.1 and the resulting
annual average expected price at Henry Hub is depicted in Figure 6.4 below.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 126 of 184
Table 6.1: Price Blend Methodology
Years Price Blend Methodology
2021 & 2022 forward price only
2023 forward price / 25% average consultant
forecasts
2024 50% forward price / 50% average consultant
forecasts
2025 25% forward price / 75% average consultant
forecasts
2026 - 2040 100% average consultant forecasts

Figure 6.4: Expected Price with Allocated Price Forecast

To accommodate for the likelihood that the expected prices at Henry Hub do not perfectly
reflect future natural gas prices and to help measure price risk in resource planning, a
stochastic analysis of 1,000 possible futures were modeled based on the expected price
forecast. Each future contains unique monthly price movements throughout the twenty-
year forecasting horizon. With the assistance of the TAC, Avista selected the 95th and
25th highest prices in each month from the stochastic results to determine high and low
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 127 of 184
price curves, respectively. The high, expected, and low price curves in nominal dollars
are illustrated in Figure 6.5 below.
Figure 6.5: Henry Hub Forecasts for IRP Low/ Expected/ High Forecasted Price –
Nominal $/Dth

Henry Hub is located in southeastern Louisiana, near the Gulf of Mexico. It is recognized
as the most important pricing point in the U.S. due to its proximity to a large portion of
U.S. natural gas production and the sheer volume traded in the daily, or spot, market and
forward markets via the NYMEX futures contracts. Consequently, prices at other trading
points tend to follow the Henry Hub with a positive or negative basis differential. Of the
two market consultants Avista uses, only one forecasts basis pricing at the gas hubs
modeled throughout the twenty-year horizon.
The natural gas hubs at Sumas, AECO, and the Rockies (and other secondary regional
market hubs) determine Avista’s costs. Prices at these points typically trade at a discount,
or negative basis differential, to Henry Hub because of their proximity to the largest natural
gas basins in North America (Western Canada and the Rockies). Figure 6.6 below shows
the resulting regional prices as compared to the Henry Hub.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 128 of 184
Figure 6.6: Regional Price as a compared to the Henry Hub Price
Carbon Policy Resource Utilization Summary
Avista uses an estimated carbon price as an incremental adder to address any potential
policy. Carbon adders increase the price of a dekatherm of natural gas and impact
resource selections and demand through expected elasticity (Chapter 2 – Demand
Forecasts, Price Elasticity). Oregon was assumed to have a cap and reduce market as
estimated by Wood Mackenzie, through a cap and trade estimate, and presented to the
TAC on September 30, 2020. In this price estimate, the initial level starts low per
MTCO2e at around $15.83, rising to $97.90 by 2040. The cap and reduce market
discussed in Oregon’s EO 20-041 is still under development at the time of this filing
making modeling of a market price difficult. Washington State was modeled at $79.86
per MTCO2e starting in 2021 and rising to $158.06 per MTCO2e by 2040. These
carbon tax figures are based on the requirement to utilize SCC at 2.5% discount
estimates from the EPA as required by RCW 80.28.395. The State of Idaho does not
have a carbon adder as there is no current or proposed state or federal legislation
associated with carbon in that jurisdiction.

Avista also completed sensitivities to account for risk including a lower and higher than
expected price of carbon and are applied to all three jurisdictions. The low carbon price
is assumed at $0, or no cost, of carbon to help measure the risk of a continued stalemate
1 https://www.oregon.gov/gov/Documents/executive_orders/eo_20-04.pdf
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 129 of 184
with carbon pricing. The high carbon price is the EPA’s high impact scenario of the
average of 95 percent of results at a 3 percent discount rate. This rate produces a much
higher cost of carbon beginning in 2021 at $151.01 and increasing to $219.33 per
MTCO2e by 2040. The effect of these modeled carbon prices, combined with our
expected elasticity as described in Chapter 2 Demand Forecasts, change demand as
shown in Figure 6.7.
Figure 6.7: Carbon Legislation sensitivities

Transportation and Storage
Valuing natural gas supplies is a critical first step in resource integration. Equally
important is capturing all costs to deliver the natural gas to customers. Daily capacity of
existing transportation resources (described in Chapter 4 – Supply-Side Resources) is
represented by the firm resource duration curves depicted in Figures 6.8 and 6.9.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 130 of 184
Figure 6.8: Existing Firm Transportation Resources – Washington & Idaho
Figure 6.9: Existing Firm Transportation Resources – Oregon
0
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1 31 61 91 121 151 181 211 241 271 301 331 361
MDth
Day of Year
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1 31 61 91 121 151 181 211 241 271 301 331 361
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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 131 of 184
Current rates for capacity are in Appendix 6.1 – Monthly Price Data by Basin. Forecasting
future pipeline rates can be challenging because of the need to estimate the amount and
timing of rate changes. Avista’s estimates and timing of future pipeline rate increases are
based on knowledge obtained from industry discussions and participation in pipeline rate
cases. This IRP assumes pipelines will file to recover costs at rates equal to increases in
GDP (see Appendix 6.2 – Weighted Average Cost of Capital).

Demand-Side Management
Chapter 3 – Demand-Side Resources describes the methodology used to identify
conservation potential and the interactive process that utilizes avoided cost thresholds for
determining the cost effectiveness of conservation measures on an equivalent basis with
supply-side resources.

Demand Results
After incorporating the above data into the SENDOUT® model, Avista generated an
assessment of demand compared to existing resources for several scenarios. Chapter 2
– Demand Forecasts discusses the demand results from these cases, with additional
details in Appendices 2.1 through 2.9.
Figures 6.10 through 6.13 provide graphic summaries of Average Case demand as
compared to existing resources on a peak day. This demand is net of conservation
savings and shows the adequacy of Avista’s resources under normal weather conditions.
For this case, current resources meet demand needs over the planning horizon.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 132 of 184
Figure 6.10: Average Case – Washington/Idaho Existing Resources vs. Average
Demand – February 28th

Figure 6.11: Average Case – Medford / Roseburg Existing Resources vs. Average
Demand – December 20th

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 133 of 184
Figure 6.12: Average Case – Klamath Falls Existing Resources vs. Average
Demand – December 20th

Figure 6.13: Average Case – La Grande Existing Resources vs. Average Demand
February 28th

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 134 of 184
Figures 6.14 through 6.17 summarize Expected Case peak day demand compared to
existing resources, as well as demand comparisons to the 2018 IRP. This demand is net
of conservation savings. Based on this information Avista has time to carefully monitor,
plan and analyze potential resource additions as described in the Ongoing Activities
section of Chapter 9 – Action Plan. Any underutilized resources will be optimized to
mitigate the costs incurred by customers until the resource is required to meet demand.
This management, of both long- and short-term resources, ensures the goal to meet firm
customer demand in a reliable and cost-effective manner as described in Supply Side
Resources – Chapter 4.
Figure 6.14: Expected Case – Washington & Idaho Existing Resources vs. Peak
Day Demand – February 28th

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 135 of 184
Figure 6.15: Expected Case – Medford / Roseburg Existing Resources vs. Peak
Day Demand – December 20th

Figure 6.16: Expected Case – Klamath Falls Existing Resources vs. Peak Day
Demand – December 20th

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 136 of 184
Figure 6.17: Expected Case – La Grande Existing Resources vs. Peak Day
Demand – February 28th
If demand grows faster than expected, the need for new resources will be earlier. Flat
demand risk requires close monitoring for signs of increasing demand and reevaluation
of lead times to acquire preferred incremental resources. The monitoring of flat demand
risk includes a reconciliation of forecasted demand to actual demand on a monthly basis.
This reconciliation helps identify customer growth trends and use-per-customer trends. If
they meaningfully differ compared to forecasted trends, Avista will assess the impacts on
planning from procurement and resource sufficiency standing.
Table 6.2 quantifies the forecasted total demand net of conservation savings and
unserved demand from the above charts.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 137 of 184
Table 6.2: Peak Day Demand – Served and Unserved (MDth/day)

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 138 of 184
New Resource Options
When existing resources are insufficient to meet expected demand, there are many
important considerations in determining the appropriateness of potential resources.
Interruptible customers’ transportation may be cut, as needed, when resources are not
sufficient to meet firm customer demand.
Resource Cost
Resource cost is the primary consideration when evaluating resource options, although
other factors mentioned below also influence resource decisions. Newly constructed
resources are typically more expensive than existing resources, but existing resources
are in shorter supply. Newly constructed resources provided by a third party, such as a
pipeline, may require a significant contractual commitment. However, newly constructed
resources are often less expensive per unit, if a larger facility is constructed, because of
economies of scale.
Lead Time Requirements
New resource options can take one to five or more years to put in service. Open season
processes to determine interest in proposed pipelines, planning and permitting,
environmental review, design, construction, and testing contribute to lead time
requirements for new facilities. Recalls of released pipeline capacity typically require
advance notice of up to one year. Even DSM programs can require significant time from
program development and rollout to the realization of natural gas savings.
Peak versus Base Load
Avista’s planning efforts include the ability to serve firm natural gas loads on a peak day,
as well as all other demand periods. Avista’s core loads are considerably higher in the
winter than the summer. Due to the winter-peaking nature of Avista’s demand, resources
that cost-effectively serve the winter without an associated summer commitment may be
preferable. Alternatively, it is possible that the costs of a winter-only resource may exceed
the cost of annual resources after capacity release or optimization opportunities are
considered.
Resource Usefulness
Available resources must effectively deliver natural gas to the intended region. Given
Avista’s unique service territories, it is often impossible to deliver resources from a
resource option, such as storage, without acquiring additional pipeline transportation.
Pairing resources with transportation increases cost. Other key factors that can contribute
to the usefulness of a resource are viability and reliability along with carbon intensity. If
the potential resource is either not available currently (e.g., new technology) or not reliable
on a peak day (e.g., firm), they may not be considered as an option for meeting unserved
demand.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 139 of 184
“Lumpiness” of Resource Options
Newly constructed resource options are often “lumpy.” This means that new resources
may only be available in larger-than-needed quantities and only available every few
years. This lumpiness of resources is driven by the cost dynamics of new construction,
where lower unit costs are available with larger expansions and the economics of
expansion of existing pipelines or the construction of new resources dictate additions
infrequently. The lumpiness of new resources provides a cushion for future growth.
Economies of scale for pipeline construction provide the opportunity to secure resources
to serve future demand increases.
Competition
LDCs, end-users and marketers compete for regional resources. The Northwest has
efficiently utilized existing resources and has an appropriately sized system. Currently,
the region can accommodate the regional demand needs. However, future needs vary,
and regional LDCs may find they are competing with other parties to secure firm
resources for customers. RNG resources specifically will have an increased amount of
competition as the drive for carbon reducing supplies increases with associated policy.
Risks and Uncertainties
Investigation, identification, and assessment of risks and uncertainties are critical
considerations when evaluating supply resource options. For example, resource costs
are subject to degrees of estimation, partly influenced by the expected timeframe of the
resource need and rigor determining estimates, or estimation difficulties because of the
uniqueness of a resource. Lead times can have varying degrees of certainty ranging from
securing currently available transport (high certainty) to building underground storage
(low certainty).
Demand-Side Resources
Integration by Price
As described in Chapter 3 – Demand-Side Resources, the model runs without future DSM
programs. This preliminary model run provides an avoided cost curve for both Applied
Energy Group (AEG) and Energy Trust of Oregon (ETO) to evaluate the cost
effectiveness of DSM programs against the initial avoided cost curve using the Utility Cost
Test, Program Administrator Costs Test, Total Resource Cost Test, and Participant Cost
Test. The therm savings and associated program costs are incorporated into the
SENDOUT® model. After incorporation, the avoided costs are re-evaluated. This process
continues until the change in avoided cost curve is immaterial.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 140 of 184
Avoided Cost
The SENDOUT® model determined avoided-cost figures represent the unit cost to serve
the next unit of demand with a supply-side resource option during a given period. If a
conservation measure’s total resource cost (Oregon), or utility cost (for Idaho and
Washington), is less than this avoided cost, it will be cost effective to reduce customer
demand and Avista can avoid commodity, storage, transportation and other supply
resource costs while reducing the risk of unserved demand in peak weather.
SENDOUT® calculates marginal cost data by day, month and year for each demand area.
A summary graphical depiction of avoided annual and winter costs for each jurisdictional
area is in Figure 6.18. The detailed data is in Appendix 6.4 – Avoided Cost Details. Other
than the carbon tax adder, avoided costs include additional environmental externality
adders for adverse environmental impacts. Appendix 3.2 – Environmental Externalities
discusses this concept more fully and includes specific requirements required in modeling
for the Oregon service territory.
Figure 6.18: Avoided Cost (by jurisdiction)
Conservation Potential
Using the avoided cost thresholds, AEG selected all potential cost-effective DSM
programs for the Idaho and Washington service areas, while ETO performed the CPA
study for Oregon. Table 6.3 shows potential DSM savings in each region from the
selected conservation potential for the Expected Case.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 141 of 184
Table 6.3: Annual and Average Daily Demand Served by Conservation

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 142 of 184
Conservation Acquisition Goals
The avoided cost established in SENDOUT®, the conservation potential selected, and
the amount of therm savings is the basis for determining conservation acquisition goals
and subsequent DSM program implementation planning. Chapter 3 – Demand-Side
Resources has additional details on this process.
Supply-Side Resources
SENDOUT® considers all options entered into the model, determines when and what
resources are needed, and which options are cost effective. Selected resources represent
the best cost/risk solution, within given constraints, to serve anticipated customer
requirements. Since the Expected Case has no resource additions in the planning
horizon, Avista will continue to review and refine knowledge of resource options and will
act to secure best cost/risk options when necessary or advantageous.
Resource Utilization
Avista plans to meet firm customer demand requirements in a cost-effective manner. This
goal encompasses a range of activities from meeting peak day requirements in the winter
to acting as a responsible steward of resources during periods of lower resource
utilization. As the analysis presented in this IRP indicates, Avista has ample resources to
meet highly variable demand under multiple scenarios, including peak weather events.
Avista acquired most of its upstream pipeline capacity during the deregulation or
unbundling of the natural gas industry. Pipelines were required to allocate capacity and
costs to their existing customers as they transitioned to transportation only service
providers. The FERC allowed a rate structure for pipelines to recover costs through a
Straight Fixed Variable rate design. This structure is based on a higher reservation charge
to cover pipeline costs whether natural gas is transported or not, and a much smaller
variable charge which is incurred only when natural gas is transported. An additional fuel
charge is assessed to account for the compressors required to move the natural gas to
customers. Avista maintains enough firm capacity to meet peak day requirements under
the Expected Case in this IRP. This requires pipeline capacity contracts at levels in
excess of the average and above minimum load requirements. Given this load profile and
the Straight Fixed Variable rate design, Avista incurs ongoing pipeline costs during non-
peak periods.
Avista chooses to have an active, hands-on management of resources to mitigate
upstream pipeline and commodity costs for customers when the capacity is not utilized
for system load requirements. This management simultaneously deploys multiple long-
and short-term strategies to meet firm demand requirements in a cost effective manner.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 143 of 184
These strategies and plan is discussed in detail in Chapter 4 – Supply side resources.
The resource strategies addressed are:
• Pipeline contract terms;
• Pipeline capacity;
• Storage;
• Commodity and transport optimization; and
• Combination of available resources.

Pipeline Contract Terms
Some pipeline costs are incurred whether the capacity is utilized or not. Winter demand
must be satisfied, and peak days must be met. Ideally, capacity could be contracted from
pipelines only for the time and days it is required. Unfortunately, this is not how pipelines
are contracted or built. Long-term agreements at fixed volumes are usually required for
building or acquiring firm transport. This assures the pipeline of long-term, reasonable
cost recovery.
Avista has negotiated and contracted for several seasonal transportation agreements.
These agreements allow volumes to increase during the demand intensive winter months
and decrease over the lower demand summer period. This is a preferred contracting
strategy because it eliminates costs when demand is low. Avista refers to this as a front
line strategy because it attempts to mitigate costs prior to contracting the resource. Not
all pipelines offer this option. Avista seeks this type of arrangement where available.
Avista currently has some seasonal transportation contracts on TransCanada GTN in
addition to contracted volumes of TF2 on NWP. This is a storage specific contract and
matches up the withdrawal capacity at Jackson Prairie with pipeline transport to Avista’s
service territories. TF2 is a firm service and allows for contracting a daily amount of
transportation for a specified number of days rather than a daily amount on an annual
basis as is usually required. For example, one of the TF2 agreements allows Avista to
transport 91,200 Dth/day for 31 days. This is a more cost-effective strategy for storage
transport than contracting for an annual amount. Through NWP’s tariff, Avista maintains
an option to increase and decrease the number of days this transportation option is
available. More days correspond to increased costs, so balancing storage, transport and
demand is important to ensure an optimal blend of cost and reliability.
Pipeline Capacity
After contracting for pipeline capacity, its management and utilization determine the
actual costs. The worst-case economic scenario is to do nothing and simply incur the
costs associated with this transport contract over the long-term to meet current and future
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 144 of 184
peak demand requirements. Avista develops strategies to ensure this does not happen
on a regular basis if possible.
Capacity Release
Through the pipeline unbundling of transportation, the FERC establishes rules and
procedures to ensure a fair market developed to manage pipeline capacity as a
commodity. This evolved into the capacity release market and is governed by FERC
regulations through individual pipelines. The pipelines implement the FERC’s posting
requirements to ensure a transparent and fair market is maintained for the capacity. All
capacity releases are posted on the pipelines Bulletin Boards and, depending on the
terms, may be subject to bidding in an open market. This provides the transparency
sought by the FERC in establishing the release requirements. Avista utilizes the capacity
release market to manage both long-term and short-term transportation capacity.
For capacity under contract that may exceed current demand, Avista seeks other parties
that may need it and arranges for capacity releases to transfer rights, obligations and
costs. This shifts all or a portion of the costs away from Avista’s customers to a third party
until it is needed to meet customer demand.
Many variables determine the value of natural gas transportation. Certain pipeline paths
are more valuable and this can vary by year, season, month and day. The term, volume
and conditions present also contribute to the value recoverable through a capacity
release. For example, a release of winter capacity to a third party may allow for full cost
recovery; while a release for the same period that allows Avista to recall the capacity for
up to 10 days during the winter may not be as valuable to the third party, but of high value
to us. Avista may be willing to offer a discount to retain the recall rights during high
demand periods. This turns a seasonal-for-annual cost into a peaking-only cost. Market
terms and conditions are negotiated to determine the value or discount required by both
parties.
Avista has several long-term releases, some extending multiple years, providing full
recovery of all the pipeline costs. These releases maintain Avista’s long-term rights to the
transportation capacity without incurring the costs of waiting until demand increases. As
the end of these release terms near, Avista surveys the market against the IRP to
determine if these contracts should be reclaimed or released, and for what duration.
Through this process, Avista retains the rights to vintage capacity without incurring the
costs or having to participate in future pipeline expansions that will cost more than current
capacity.
On a shorter term, excess capacity not fully utilized on a seasonal, monthly or daily basis
can also be released. Market conditions often dictate less than full cost recovery for
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 145 of 184
shorter-term requirements. Mitigating some costs for an unutilized, but required resource
reduces costs to our customers.
Segmentation
Through a process called segmentation, Avista creates new firm pipeline capacity for the
service territory. This doubles some of the capacity volumes at no additional cost to
customers. With increased firm capacity, Avista can continue some long-term releases,
or even reduce some contract levels, if the release market does not provide adequate
recovery. An example of segmentation is if the original receipt and delivery points are
from Sumas to Spokane. Avista can alter this path from Sumas to Sipi, Sipi to Jackson
Prairie, Jackson Prairie to Spokane. This segmentation allows Avista to flow three times
the amount of natural gas on most days or non-peak weather events. In the event of a
peak day, and the transport needs to be firm, the transportation can be rolled back up to
ensure the natural gas will be delivered into the original firm path.
Storage
As a one-third owner of the Jackson Prairie Storage facility, Avista holds an equal share
of capacity (space available to store natural gas) and delivery (the amount of natural gas
that can be withdrawn daily).
Storage allows lower summer-priced natural gas to be stored and used in the winter
during high demand or peak day events. Like transportation, unneeded capacity and
delivery can be optimized by selling into a future higher priced market. This allows Avista
to manage storage capacity and delivery to meet growing peak day requirements when
needed.
The injection of natural gas into storage during the summer utilizes existing pipeline
transport and helps increase the utilization factor of pipeline agreements. Avista employs
several storage optimization strategies to mitigate costs. Revenue from this activity flows
through the annual PGA/Deferral process.
Commodity and Transportation Optimization
Another strategy to mitigate transportation costs is to participate in the daily market to
assess if unutilized capacity has value. Avista seeks daily opportunities to purchase
natural gas, transport it on existing unutilized capacity, and sell it into a higher priced
market to capture the cost of the natural gas purchased and recover some pipeline
charges. The amount of recovery is market dependent and may or may not recover all
pipeline costs but does mitigate pipeline costs to customers.
Combination of Resources
Unutilized resources like supply, transportation, storage and capacity can combine to
create products that capture more value than the individual pieces. Avista has structured
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 146 of 184
long-term arrangements with other utilities that allow available resource utilization and
provide products that no individual component can satisfy. These products provide more
cost recovery of the fixed charges incurred for the resources while maintaining the rights
to utilize the resource for future customer needs.
Resource Utilization Summary
As determined through the IRP modeling of demand and existing resources, new
resources under the Expected Case are not required over the next 20 years. Avista
manages the existing resources to mitigate the costs incurred by customers until the
resource is required to meet demand. The recovery of costs is often market based with
rules governed by the FERC. Avista is recovering full costs on some resources and partial
costs on others. The management of long- and short-term resources meets firm customer
demand in a reliable and cost-effective manner.
Conclusion
Choosing reliable information and methods to utilize in these analyses help Avista
determine an expected standard. To do this, Avista utilizes industry experts to help
determine prices and a market environment, decades of historic weather by major service
area, daily weather adjusted usage metrics combined with a statistical based customer
forecast all help to provide a reasonable range of expectations for this planning period.
There are no expected resource deficiencies during this 20-year forecast in either the
Average Case or Expected Case in this IRP. Avista will rely on its Expected Case for
peak operational planning activities and in its optimization programs to sufficiently plan
for cold day events.
Avista recognizes that there are other potential outcomes. The process described in this
chapter applies to the alternate demand and supply resource scenarios covered in
Chapter 7 – Alternate Scenarios, Portfolios and Stochastic Analysis.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 147 of 184

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 148 of 184
7: Alternate Scenarios, Portfolios and Stochastic
Analysis
Overview
Avista applied the IRP analysis in Chapter 6 – Integrated Resource Portfolio to alternate
demand and supply resource scenarios to develop a range of alternate portfolios. This
modeling approach considered different underlying assumptions vetted with the TAC
members to develop a consensus about the number of cases to model.
Avista also performed stochastic modeling for estimating probability distributions of
potential outcomes by allowing for random variation in natural gas prices and weather
based on fluctuations in historical data. This statistical analysis, in conjunction with the
deterministic analysis, enabled statistical quantification of risk from reliability and cost
perspectives related to resource portfolios under varying price and weather conditions.

Alternate Demand Scenarios
As discussed in the Demand Forecasting section, Avista identified alternate scenarios for
detailed analysis to capture a range of possible outcomes over the planning horizon.
Table 7.1 summarizes these scenarios and Chapter 2 – Demand Forecasts and
Appendices 2.6 and 2.7 describes them in detail. The scenarios consider different
demand influencing factors and price elasticity effects for various price influencing factors.

Table 7.1: 2021 IRP Scenarios

Demand profiles over the planning horizon for each of the scenarios shown in Figures 7.1
and 7.2 reflect the two winter peaks modeled for the different service territories.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 149 of 184
Figure 7.1: Peak Day (Feb 28) – 2021 IRP Demand Scenarios
Figure 7.2: Peak Day (Dec 20) – 2021 IRP Demand Scenarios
As in the Expected Case, Avista used SENDOUT® to model the same resource
integration and optimization process described in this section for each of the five demand
scenarios (see Appendix 2.7 for a complete listing of portfolios considered). This
deterministic analysis identified the first-year unserved dates for each scenario by service
territory shown in Figure 7.3.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 150 of 184
Figure 7.3: First Year Peak Demand Not Met with Existing Resources

Steeper demand highlights the flat demand risk discussed earlier. This could be a regional
issue with utilities look toward carbon reduction with limited resources available. The
likelihood of this scenario occurring is remote due to a yearly recurrence of the weather
planning standard paired with a much steeper growth of customer population; however,
any potential for accelerated unserved dates warrants close monitoring of demand trends
and resource lead times as described in the Ongoing Activities section of Chapter 9 –
Action Plan. The remaining scenarios do not identify resource deficiencies in the planning
horizon.

Alternate Supply Resources
Avista identified supply-side resources that could meet resource deficiencies or provide
a least cost solution. There are other options Avista considered in its modeling approach
to solve for High Growth & Low-Price unserved conditions and to determine whether the
Expected Case with existing resources is least cost/least risk. A list of the modeled
available renewable supply resources is displayed in Table 7.2 and fossil resources are
included in Table 7.3.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 151 of 184
Table 7.2: Levelized Cost of Renewable Resources
Resource Dth per
year
20-year Levelized Cost
Per Dth (Year 1)
$ per kWh
(retail)
Distributed Renewable
Hydrogen Production 60,509 $47.25 $0.161
Distributed LFG to RNG
Production 231,790 $15.90 $0.054
Centralized LFG to RNG
Production 662,256 $14.11 $0.048
Dairy Manure to RNG
Production 231,790 $14.30 $0.049
Wastewater Sludge to RNG
Production 187,245 $23.34 $0.080
Food Waste to RNG Production 108,799 $33.14 $0.113

Table 7.3: Other Supply Resources

Additional
Resource Size Cost/Rates Availability Notes
Unsubscribed
GTN Capacity
Up to
50,000 Dth GTN Rate 2021
Currently available
unsubscribed capacity from
Kingsgate to Spokane
Medford
Lateral
Expansion
50,000 Dth /
Day
$35M
capital +
GTN Rate
2022
Additional compression to
facilitate more gas to flow
from mainline GTN to
Medford
Plymouth
LNG
241,700 Dth
w/70,500
Dth
deliverability
NWP Rate 2021
Provides for peaking
services and alleviates the
need for costly pipeline
expansions

Pair with excess pipeline
MDDO’s to create firm
transport

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 152 of 184
As discussed in Chapter 5 – Carbon Reduction, Hydrogen is beginning to emerge as a
true potential as a clean fuel to help offset emissions in the natural gas system. Excess
electricity from renewable resources can create green. Not only will this act as a type of
storage desperately needed by the electric grid, it will capture excess green energy for
future use. Some estimates have green hydrogen as a major fuel in the supply mix by
2050. However, the market-based price and other terms are difficult to reliably determine
until a formal agreement is negotiated. Exchange agreements also have market-based
terms and are hard to reliably model when the resource need is later in the planning
horizon. Current tariff prices were used to model additional GTN capacity and Plymouth
LNG, while an estimate was provided from GTN for the upsized Medford lateral
compressor combined with tariff rates in order to flow the gas. For those costs specifically
related to all four RNG projects and hydrogen Avista contracted with a consultant to
provide cost estimates for these types of facilities. Some of the major costs include:
Capital, O&M, Avista’s revenue requirement, federal income tax, and depreciation. Avista
also included any subsidies known at the time of modeling. These projects include a cost
of carbon adder for any amount of carbon intensity still associated with each project type.
Specifically, dairy and solid waste have a negative carbon intensity, as discussed in
Chapter 5. The net effect of using this is the removal of carbon from the atmosphere.
Finally, Renewable Identification Number (RIN) values were not included in the valuation
of RNG as it is assumed that these RIN’s would be needed to provide proof of Avista’s
utilization of RNG or in complying with new environmental legislation1.
Many of the potential resources are not yet commercially available or well tested,
technically making them speculative. Avista will continue to monitor all resources and
assess their appropriateness for inclusion in future IRPs as described in Chapter 9 –
Action Plan.

Deterministic – Portfolio Evaluation
There is no resource deficiency identified in the planning period and the existing resource
portfolio is adequate to meet forecasted demand. The alternate demand scenarios and
supply scenarios are placed in the model as predicted future conditions that the supply
portfolio will have to satisfy via least cost and least risk strategies. This creates bounds
for analyzing the Expected Case by creating high and low boundaries for customer count,
weather and pricing. Each portfolio runs through SENDOUT® where the supply resources
(Chapter 4 – Supply Side Resources) and conservation resources (Chapter 3 – Demand
Side Management) are compared and selected on a least cost basis. Once new
1 https://www.epa.gov/renewable-fuel-standard-program/renewable-identification-numbers-rins-under-renewable-fuel-
standard
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 153 of 184
resources are determined, a net present value of the revenue requirement (PVRR) is
calculated. Results from each scenario can be found in Table 7.4.
Table 7.4: PVRR by Portfolio
Scenario
System Cost
(PVRR)
Billions of $
Expected Case $6.88
High Growth & Low Prices $2.68
Carbon Reduction* $5.70
Average Case $5.69
Low Growth & High Prices $9.80
*Carbon Reduction Scenario does not have sufficient factors to stochastically represent alternative futures due to
the unknown nature of the cost and availability of RNG and H2.
Stochastic Analysis2
The scenario (deterministic) analysis described earlier in this chapter represents specific
what if situations based on predetermined assumptions, including price and weather.
These factors are an integral part of scenario analysis. To understand how each scenario
will respond to cost and risk, through price and weather, Avista applied stochastic analysis
to generate a variety of price and weather events.
Deterministic analysis is a valuable tool for selecting an optimal portfolio. The model
selects resources to meet peak weather conditions in each of the 20 years. However, due
to the recurrence of design conditions in each of the 20 years, total system costs over the
planning horizon can be overstated because of annual recurrence of design conditions
and the recurrence of price increases in the forward price curve. As a result, deterministic
analysis does not provide a comprehensive look at future events. Utilizing Monte Carlo
simulation in conjunction with deterministic analysis provides a more complete picture of
portfolio performance under unknown weather and price profiles.
This IRP employs stochastic analysis in two ways. The first tested the weather-planning
standard and the second assessed risk related to costs of our Expected Case (existing
portfolio) under varying price environments. The Monte Carlo simulation in SENDOUT®
can vary index price and weather simultaneously. This simulates the effects each have
on the other.
2 SENDOUT® uses Monte Carlo simulation to support stochastic analysis, which is a mathematical technique for evaluating risk and uncertainty. Monte Carlo simulation is a statistical modeling method used to imitate future
possibilities that exist with a real-life system.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 154 of 184
Weather
In order to evaluate weather and its effect on the portfolio, Avista developed 1,000
simulations (draws) through SENDOUT®’s stochastic capabilities. Unlike deterministic
scenarios or sensitivities, the draws have more variability from month-to-month and year-
to-year. In the model, random monthly total HDD draw values (subject to Monte Carlo
parameters – see Table 7.5) are distributed on a daily basis for a month in history with
similar HDD totals. The resulting draws provide a weather pattern with variability in the
total HDD values, as well as variability in the shape of the weather pattern. This provides
a more robust basis for stress testing the deterministic analysis.
Table 7.5: Example of Monte Carlo Weather Inputs – Spokane

The model considers five weather areas: Spokane, Medford, Roseburg, Klamath Falls
and La Grande. A new weather planning standard was introduced into the 2021 IRP, and
Avista assessed the frequency of the weather planning standard peak day occurs in each
area from the simulation data. The stochastic analysis shows that in over 1,000, 20-year
simulations, peak day (or more) occurs with enough frequency to utilize the new planning
standard for the current IRP. This topic remains a subject of continued analysis. For
example, the Medford weather pattern over the 1,000 20-year draws (i.e, 20,000 years)
HDDs at or above peak weather (49 HDDs) occur 1,926 times or once every 10 years.
See Figures 7.4 through 7.8 for the number of peak day occurrences by weather area.
help explain why this can occur we look to the process itself. Monte Carlo simulations use
historic data to obtain randomly generated weather events. Due to the change in planning
standard, no peak days were simulated above the historic coldest on record temperature.
Though due to the number of peak days occurring in the past 30 years, probability sees
it is a higher likelihood of occurrence.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 155 of 184
Figure 7.4: Frequency of Peak Day Occurrences – Spokane

Figure 7.5: Frequency of Peak Day Occurrences – Medford

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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 156 of 184
Figure 7.6: Frequency of Peak Day Occurrences – Roseburg

Figure 7.7: Frequency of near Peak Day Occurrences – Klamath Falls

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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 157 of 184
Figure 7.8: Frequency of near Peak Day Occurrences – La Grande
Price
While weather is an important driver for the IRP, price is also important. As seen in recent
years, significant price volatility can affect the portfolio. In deterministic modeling, a single
price curve for each scenario is used for analysis. There is risk that the price curve in the
scenario will not reflect actual results.
Avista used Monte Carlo simulation to test the portfolio and quantify the risk to customers
when prices do not materialize as forecast. Avista performed a simulation of 1,000 draws,
varying prices, to investigate whether the Expected Case total portfolio costs from the
deterministic analysis is within the range of occurrences in the stochastic analysis. Figure
6.9 shows a histogram of the total portfolio cost of all 1,000 draws, plus the Expected
Case results. This histogram depicts the frequency and the total cost of the portfolio
among all of the draws, the mean of the draws, the standard deviation of the total costs,
and the total costs from the Expected Case.

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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 158 of 184
Figure 7.9: 2018 IRP Total 20-Year Cost
(Billions of $)

Measuring risk in both weather and price is done through a statistical approach of
shocking each of these measures to reflect the uncertain nature of a future outcome. Risk
can be measured in the variation of cost outcome of resources in addition to unknown
weather events and the ability to serve customer demand. This analytical perspective
provides confidence in the conclusions and stress tests the robustness of the selected
portfolio of resources, thereby mitigating analytical risks.

Solving Unserved Demand
High Growth & Low Price
The components, methods and topics covered in this and previous chapters will now help
to solve unserved demand in The High Growth & Low Price scenario. This scenario
includes customer growth rates higher than the Expected Case, incremental demand
driven by emerging markets and no adjustment for price elasticity. Even with aggressive
assumptions, deterministic analysis shows resource shortages do not occur until late in
the planning horizon.
• 2036 in Washington/Idaho
• 2040 in La Grande
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 159 of 184
We begin to solve for unserved demand by adding additional resources as supply side
options. The resources Avista modeled for the current IRP include 5 types of renewable
natural gas, hydrogen, and an upsized compressor on the Medford lateral, additional GTN
capacity and Plymouth LNG as seen in Table 7.2. All costs are entered by location with
the associated daily, pipeline quality, volume available to inform the model. A
deterministic resource mix is performed allowing the model to solve the demand based
on the optimal least cost solution for the system. Avista performed this selection process
both deterministically and stochastically with the statistical measures shown for each
resource option as illustrated in Table 7.6.
Table 7.6: System Cost, Standard Deviation and Outcome of Adding Resource to
System
Solve – No Unserved Average Stdev Median Max Min
RNG Resources Only $2.683 $0.043 $2.681 $2.861 $2.542
Plymouth, RNG in La Grande $2.721 $0.043 $2.719 $2.901 $2.580
GTN – RNG in La Grande $2.734 $0.042 $2.675 $2.855 $2.540
Medford Lateral Expansion,
RNG in La Grande $2.734 $0.044 $2.731 $2.915 $2.600
*$ in Billions
**1,000 draws each scenario
Once an optimal resource is found deterministically a stochastic analysis takes place to
measure risk. Figure 7.10 shows the frequency of occurrence from the solve (RNG
Resources Only) by cost in addition to a running sum of overall percentage of the total
number of future 20 year draws.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 160 of 184
The Optimal Solution Figure 7.10: High Growth and Low Price Cost vs. Risk
(1,000 Draws – Billions of $)

Carbon Reduction Scenario
As carbon policy continues to shift and evolve, mapping out potential supply options to
meet these climate goals is increasingly important. Understanding the dynamic between
serving the energy demand while reducing carbon emissions is a relatively new paradigm
in the natural gas industry. Reducing carbon can take the form of alternate fuel choices
either partially reducing, increased energy efficiency (DSM) or fully offsetting the carbon
intensity of fossil natural gas. Some RNG sources, as mentioned in Chapter 5 – Carbon
Reduction, will turn each unit of energy into a methodology to capture carbon rather than
just fully offset the emissions of fossil fuel natural gas. These sources such as dairy or
WWTP RNG will leave a deficit of energy for the number of emissions offsets provided.
Pairing the right amount of energy with the necessary amount of emissions reduction is
where this IRP will begin to discover solutions and provide answers.
Future IRP’s will have the ability to solve for emissions and costs to meet a dual goal least
cost and risk set of supply side resources. Emissions reduction goals can be measured
to include various goals as a percentage based on a specific year or timeframe. In this
scenario, we take the Expected case assumptions as inputs and combine them with an
estimated 1990 emissions goal for Oregon and Washington. The emissions reduction for
Oregon and Washington can be seen in Figure 7.11.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 161 of 184
Figure 7.11: Expected Emissions vs. Emissions with Climate Goals (Net of DSM)

It is assumed the goal and reductions need to be met on a yearly basis based on the
average emissions reduction needed to meet these major milestones. Carbon emissions
offsets are not modeled in the current IRP as their costs are unknown as are the allowable
quantity by timeframe for their use. The selling of carbon credits, like RINs, will need
consideration in future resource plans. As the cost of carbon increases, the levelized cost
of resources decreases especially those with the ability to capture carbon as opposed to
just offsetting emissions. This places dairy RNG into the preferred supply side resource
if the ability to obtain the quantity of projects and the respective output is available as
displayed in Figure 7.12 along with each modeled scenario’s carbon emissions (Figure
7.13).

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 162 of 184
Figure 7.12: Carbon Reduction Solve

Figure 7.13: Depicts System Emissions for each Scenario

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 163 of 184
Electrification Scenarios
Avista uses three scenarios to identify impacts to the power system if space and water
heating is electrified in the Washington service area3, specifically for the residential and
commercial customers. The first scenario of electrification uses current electric
technology and efficiency. The second, continues to use the natural gas system for peak
heating needs with non-peak electrified. Finally, the third scenario uses an assumption of
high efficiency electric equipment. Each scenario uses the conversion from natural gas
to electric assumes a 50 percent reduction in natural gas load by 2030 and an 80 percent
reduction by 2045. Avista estimates 75 percent of the added electric load will be on
Avista’s system and the remaining load on other utilities.
Figure 7.14 below illustrates additional Avista load on the Avista electric system in
Washington:
Figure 7.14: Additional Avista Load on Avista Electric System - Washington

Figure 7.15 displays the natural gas supplied for each electrification scenario:
3 The load conversion analysis also includes natural gas process conversion such as cooking, cloths drying, etc.
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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 164 of 184
Figure 7.15: Natural Gas Supply by Electrification Scenario

While these scenarios have advanced our understanding of an electrification future,
further studies are needed to fully understand the full impacts and costs of electrification.
Some of these areas include:
• cost to homeowners to convert equipment;
• transmission or distribution grid impacts and costs;
• Avista has not re-studied the northwest electric market to account for pricing and
resource availability impacts.
Given the large scope and impacts of this future scenario it may be best suited for a non-
IRP analysis on a regional level. For additional detail on these scenarios, please refer to
the Avista 2021 Electric IRP (Chapter 12-Portfolio Scenario Analysis).

Regulatory Requirements
IRP regulatory requirements in Idaho, Oregon and Washington call for several key
components. The completed plan must demonstrate that the IRP:
• Examines a range of demand forecasts.
-
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
20
2
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20
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Base LDC WA Forecast Hybrid Future Current Technology/High Efficiency Future
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 165 of 184
•Examines feasible means of meeting demand with both supply-side and demand-
side resources.
•Treats supply-side and demand-side resources equally.
•Describes the long-term plan for meeting expected demand growth.
•Describes the plan for resource acquisitions between planning cycles.
•Takes planning uncertainties into consideration.
•Involves the public in the planning process.
Avista addressed the applicable requirements throughout this document. Appendix 1.2 –
IRP Guideline Compliance Summaries lists the specific requirements and guidelines of
each jurisdiction and describes Avista’s compliance.
The IRP is also required to consider risks and uncertainties throughout the planning and
analytical processes. Avista’s approach in addressing this requirement was to identify
factors that could cause significant deviation from the Expected Case planning
conclusions. This included dynamic demand analytical methods and sensitivity analysis
on demand drivers that impacted demand forecast assumptions. From this, Avista
created multiple demand sensitivities and five demand scenario alternatives, which
incorporated different customer growth, use-per-customer, weather, and price elasticity
assumptions.
Avista analyzed peak day weather planning standard, performing sensitivity on HDDs and
modeling an alternate weather-planning standard using the coldest day in 20 years.
Stochastic analysis using Monte Carlo simulations in SENDOUT® supplemented this
analysis. Avista also used simulations from SENDOUT® to analyze price uncertainty and
the effect on total portfolio cost.
Avista examined risk factors and uncertainties that could affect expectations and
assumptions with respect to DSM programs and supply-side scenarios. From this, Avista
assessed the expected available supply-side resources and potential conservation
savings for evaluation.
The investigation, identification, and assessment of risks and uncertainties in our IRP
process should reasonably mitigate surprise outcomes.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 166 of 184
Conclusion
In planning, a reasonable set of criteria is necessary to help measure the inherent risk of
the unknown in future events. With the inclusion of the Carbon Reduction scenario, Avista
will continue to consider resources to solve the energy demand in combination with new
policy, specifically those requiring carbon reductions. As policy continues to require green
sources from the electric grid, the existing natural gas infrastructure should be used in the
battle against climate change. Resources such as RNG and H2 can play an important
part in these electric generation green resources, utilizing the excess energy while
providing mitigation to outages and weather-related events that are far more common in
the electric industry4. Energy security during the coldest of times is a pillar of resource
planning and Avista will continue to consider all the environment, affordability and
reliability of resources to meet our customer’s needs.

4 www.energy.gov
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 167 of 184
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 168 of 184
8: Distribution Planning
Overview
Avista’s IRP evaluates the safe, economical and reliable full-path delivery of natural gas
from basin to the customer meter. Securing adequate natural gas supply and ensuring
sufficient pipeline transportation capacity to Avista’s city gates become secondary issues
if distribution system growth behind the city gates increases faster than expected and the
system becomes severely constrained. Important parts of the distribution planning
process include forecasting local demand growth, determining potential distribution
system constraints, analyzing possible solutions and estimating costs for eliminating
constraints.
Analyzing resource needs to this point has focused on ensuring adequate capacity to the
city gates, especially during a peak event. Distribution planning focuses on determining if
there will be adequate pressure during a peak hour. Despite this altered perspective,
distribution planning shares many of the same goals, objectives, risks and solutions as
integrated resource planning.
Avista’s natural gas distribution system consists of approximately 3,300 miles of
distribution main and service pipelines in Idaho, 3,700 miles in Oregon and 5,800 miles
in Washington; as well as numerous regulator stations, service distribution lines,
monitoring and metering devices, and other equipment. Currently, there are no storage
facilities or compression systems within Avista’s distribution system. Distribution network
pipelines and regulating stations operate and maintain system pressure solely from the
pressure provided by the interstate transportation pipelines.

Distribution System Planning
Avista conducts two primary types of evaluations in its distribution system planning
efforts: capacity requirements and integrity assessments.
Capacity requirements include distribution system reinforcements and expansions.
Reinforcements are upgrades to existing infrastructure or new system additions, which
increase system capacity, reliability and safety. Expansions are new system additions to
accommodate new demand. Collectively, these reinforcements and expansions are
distribution enhancements.
Ongoing evaluations of each distribution network in the five primary service territories
identify strategies for addressing local distribution requirements resulting from customer
growth. Customer growth assessments are made based on factors including IRP demand
forecasts, monitoring gate station flows and other system metering, new service requests,
field personnel discussion, and inquiries from major developers.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 169 of 184
Avista regularly conducts integrity assessments of its distribution systems. Ongoing
system evaluation can indicate distribution-upgrading requirements for system
maintenance needs rather than customer and load growth. In some cases, the timing for
system integrity upgrades coincides with growth-related expansion requirements. These
planning efforts provide a long-term planning and strategy outlook and integrate into the
capital planning and budgeting process, which incorporates planning for other types of
distribution capital expenditures and infrastructure upgrades.
Gas Engineering planning models are also compared with capacity limitations at each
city gate station. Referred to as city gate analysis, the design day hourly demand
generated from planning analyses must not exceed the actual physical limitation of the
city gate station. A capacity deficiency found at a city gate station establishes a potential
need to rebuild or add a new city gate station.

Network Design Fundamentals
Natural gas distribution networks rely on pressure differentials to flow natural gas from
one place to another. When pressures are the same on both ends of a pipe, the natural
gas does not move. As natural gas exits the pipeline network, it causes a pressure drop
due to its movement and friction. As customer demand increases, pressure losses
increase, reducing the pressure differential across the pipeline network. If the pressure
differential is too small, flow stalls and the network could run out of pressure.
It is important to design a distribution network such that intake pressure from gate stations
and/or regulator stations within the network is high enough to maintain an adequate
pressure differential when natural gas leaves the network.
Not all natural gas flows equally throughout a network. Certain points within the network
constrain flow and restrict overall network capacity. Network constraints can occur as
demand requirements evolve. Anticipating these demand requirements, identifying
potential constraints and forming cost-effective solutions with sufficient lead times without
overbuilding infrastructure are the key challenges in network design.

Computer Modeling
Developing and maintaining effective network design is aided by computer modeling for
network demand studies. Demand studies have evolved with technology to become a
highly technical and powerful means of analyzing distribution system performance. Using
a pipeline fluid flow formula, a specified parameter for each pipe element can be
simultaneously solved. Many pipeline equations exist, each tailored to a specific flow
behavior. These equations have been refined through years of research to the point
where modeling solutions closely resemble actual system behavior.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 170 of 184
Avista conducts network load studies using GL Noble Denton’s Synergi software. This
modeling tool allows users to analyze and interpret solutions graphically.
Determining Peak Demand
Avista’s distribution network is comprised of high pressure (90-500 psig) and intermediate
pressure (5-60 psig) mains. Avista operates its intermediate networks at a maximum
pressure of 60 psig or less for ease of maintenance and operation, public safety, reliable
service, and cost considerations. Since most distribution systems operate through
relatively small diameter pipes, there is essentially no line-pack capability for managing
hourly demand fluctuations. Line pack is the difference between the natural gas contents
of the pipeline under packed (fully pressurized) and unpacked (depressurized) conditions.
Line pack is negligible in Avista’s distribution system due to the smaller diameter pipes
and lower pressures. In transmission and inter-state pipelines, line-pack contributes to
the overall capacity due to the larger diameter pipes and higher operating pressures.
Core demand typically has a morning peaking period between 6 a.m. and 10 a.m. and
the peak hour demand for these customers can be as much as 50 percent above the
hourly average of daily demand. Because of the importance of responding to hourly
peaking in the distribution system, planning capacity requirements for distribution systems
uses peak hour demand.1
Distribution System Enhancements
Demand studies facilitate modeling multiple demand forecasting scenarios, constraint
identification and corresponding optimum combinations of pipe modification, and
pressure modification solutions to maintain adequate pressures throughout the network.
Distribution system enhancements do not reduce demand, nor do they create additional
supply. Enhancements can increase the overall capacity of a distribution pipeline system
while utilizing existing gate station supply points. The two broad categories of distribution
enhancement solutions are pipelines and regulators.
Pipelines
Pipeline solutions consist of looping, upsizing and uprating. Pipeline looping is the most
common method of increasing capacity in an existing distribution system. Looping
involves constructing new pipe parallel to an existing pipeline that has, or may become,
a constraint point. Constraint points inhibit flow capacities downstream of the constraint
creating inadequate pressures during periods of high demand. When the parallel line
connects to the system, this alternative path allows natural gas flow to bypass the original
1 This method differs from the approach that Avista uses for IRP peak demand planning, which focuses on peak day
requirements to the city gate.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 171 of 184
constraint and bolsters downstream pressures. Looping can also involve connecting
previously unconnected mains. The feasibility of looping a pipeline depends upon the
location where the pipeline will be constructed. Installing natural gas pipelines through
private easements, residential areas, existing paved surfaces, and steep or rocky terrain
can increase the cost to a point where alternative solutions are more cost effective.
Pipeline upsizing involves replacing existing pipe with a larger size pipe. The increased
pipe capacity relative to surface area results in less friction, and therefore a lower
pressure drop. This option is usually pursued when there is damaged pipe or where pipe
integrity issues exist. If the existing pipe is otherwise in satisfactory condition, looping
augments existing pipe, which remains in use.
Pipeline uprating increases the maximum allowable operating pressure of an existing
pipeline. This enhancement can be a quick and relatively inexpensive method of
increasing capacity in the existing distribution system before constructing more costly
additional facilities. However, safety considerations and pipe regulations may prohibit the
feasibility or lengthen the time before completion of this option. Also, increasing line
pressure may produce leaks and other pipeline damage creating costly repairs. A
thorough review is conducted to ensure pipeline integrity before pressure is increased.
Regulators
Regulators, or regulator stations, reduce pipeline pressure at various stages in the
distribution system. Regulation provides a specified and constant outlet pressure before
natural gas continues its downstream travel to a city’s distribution system, customer’s
property or natural gas appliance. Regulators also ensure that flow requirements are met
at a desired pressure regardless of pressure fluctuations upstream of the regulator.
Regulators are at city gate stations, district regulator stations, farm taps and customer
services.
Compression
Compressor stations present a capacity enhancing option for pipelines with significant
natural gas flow and the ability to operate at higher pressures. For pipelines experiencing
a relatively high and constant flow of natural gas, a large volume compressor installation
along the pipeline boosts downstream pressure.
A second option is the installation of smaller compressors located close together or
strategically placed along a pipeline. Multiple compressors accommodate a large flow
range and use smaller and very reliable compressors. These smaller compressor stations
are well suited for areas where natural gas demand is growing at a relatively slow and
steady pace, so that purchasing and installing these less expensive compressors over
time allows a pipeline to serve growing customer demand into the future.
Compressors can be a cost-effective option to resolving system constraints; however,
regulatory and environmental approvals to install a compressor station, along with
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 172 of 184
engineering and construction time can be a significant deterrent. Adding compressor
stations typically involves considerable capital expenditure. Based on Avista’s detailed
knowledge of the distribution system, there are no foreseeable plans to add compressors
to the distribution network.

Conservation Resources
The evaluation of distribution system constraints includes consideration of targeted
conservation resources to reduce or delay distribution system enhancements. The
consumer is still the ultimate decision-maker regarding the purchase of a conservation
measure. Because of this, Avista attempts to influence conservation through the DSM
measures discussed in Chapter 3 – Demand-Side Resources, but does not depend on
estimates of peak day demand reductions from conservation to eliminate near-term
distribution system constraints. Over the longer-term, targeted conservation programs
may provide a cumulative benefit that could offset potential constraint areas and may be
an effective strategy.

Distribution Scenario Decision-Making Process
After achieving a working load study, analyses are performed on every system at design
day conditions to identify areas where potential outages may occur.

Avista’s design HDD for distribution system modeling is determined using a 99%
statistical probability method for each given service area. This practice is consistent with
the peak day demand forecast utilized in other sections of Avista’s natural gas IRP.

Utilizing a peak planning standard based on a statistical probability method of historical
temperatures may seem aggressive since extreme temperatures are experienced rarely.
Given the potential impacts of an extreme weather event on customers’ personal safety
and property damage to customer appliances and Avista’s infrastructure, it is a prudent
regionally accepted planning standard.

These areas of concern are then risk ranked against each other to ensure the highest risk
areas are corrected first. Within a given area, projects/reinforcements are selected using
the following criteria:

• The shortest segment(s) of pipe that improves the deficient part of the distribution
system.
• The segment of pipe with the most favorable construction conditions, such as
ease of access or rights or traffic issues.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 173 of 184
• Minimal to no water, railroad, major highway crossings, etc.
• The segment of pipe that minimizes environmental concerns including minimal to
no wetland involvement, and the minimization of impacts to local communities
and neighborhoods.
• The segment of pipe that provides opportunity to add additional customers.
• Total construction costs including restoration.

Once a project/reinforcement is identified, the design engineer or construction project
coordinator begins a more thorough investigation by surveying the route and filing for
permits. This process may uncover additional impacts such as moratoriums on road
excavation, underground hazards, discontent among landowners, etc., resulting in
another iteration of the above project/reinforcement selection criteria. Figure 8.1 provides
a schematic representation of the distribution scenario process.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 174 of 184
Figure 8.1: Distribution Scenario Process

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 175 of 184
An example of the distribution scenario decision making process is from the Medford high
pressure loop reinforcement where the analysis resulted in multiple paths or pipeline
routes. The initial path was based on quantitative factors, specifically the shortest length
and least cost route. However, as field investigations and coordination with local city and
county governments began, alternative routes had to be determined to minimize future
conflicts, environmental considerations, and field and community disruptions. The final
path was based on several qualitative factors that including:

• Available right-of-way along city streets;
• Availability of private easements from property owners;
• Restrictions due to City of Medford future planned growth with limited planning
information; and
• Potential to avoid conflict with other utilities including a large electric substation
along the initial route.

Planning Results
Table 8.1 summarizes the cost and timing, as of the publication date of this IRP, of major
distribution system enhancements addressing growth-related system constraints, system
integrity issues and the timing of expenditures.
The Distribution Planning Capital Projects criteria includes:

• Prioritized need for system capacity (necessary to maintain reliable service);
• Scale of project (large in magnitude and will require significant engineering
and design support); and
• Budget approval (will require approval for capital funding).
These projects are preliminary estimates of timing and costs of major reinforcement
solutions whose costs exceed $500,000 in any year. The scope and needs of distribution
system enhancement projects generally evolve with new information requiring ongoing
reassessment. Actual solutions may differ due to differences in actual growth patterns
and/or construction conditions that differ from the initial assessment and timing of planned
completion may change based on the aforementioned ongoing reassessment of
information.
The following discussion provides information about key near-term projects.
Airway Heights High Pressure Reinforcement, WA: The Airway Heights high pressure
line has provided natural gas to one of the fasted growing regions in all of Avista’s service
territories. Recent rapid growth has included both residential and industrial customers,
quickly depleting the available capacity of the high pressure line. This reinforcement will
provide additional capacity and ensure reliable pressure at the end of the high pressure
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 176 of 184
line, which supplies a major regulator station feeding the Downtown Spokane
neighborhoods.
Cheney High Pressure Reinforcement, WA: This project will reinforce the Cheney
distribution system, whose customer demands have exceeded the capacity of the high
pressure line constructed in 1957. During cold weather conditions, Avista periodically
asks some large firm customers to reduce their natural gas usage in order to serve core
customer demand. Project began in 2020 and will continue in 2021.
Pullman High Pressure Reinforcement, WA: The Pullman high pressure reinforcement
would connect both Moscow and Pullman’s high pressure systems. This would bring
Moscow gas to Pullman, avoiding the need to rebuild the Pullman City Gate Station which
is currently exceeding its physical capacity. Additionally, this interconnection would
increase reliability as both Moscow and Pullman would then have two sources of
gas. Design is tentatively scheduled for 2024 and we continue to monitor existing
customer demand. Construction timelines may change due to customer growth
expectations.

Warden High Pressure Reinforcement, WA: The Warden high pressure reinforcement
is necessary to serve either new or increased industrial customer demand. At this time,
prospective industrial customers, whose projected demands necessitated
reinforcements, have either cancelled expansion plans or are considering alternative
locations. In anticipation of similar industrial loads in the future, Avista will continue to list
this project, but defer major construction until supply constraints subside.

Table 8.1 High Pressure - Distribution Planning Capital Projects
Location 2021 2022 2023 2024 2025+
Airway Heights
High Pressure
Reinforcement, WA
$3,000,000 $3,000,000 --- --- ---
Cheney High
Pressure
Reinforcement, WA
$3,100,000 --- --- --- ---
Pullman High
Pressure
Reinforcement, WA
--- --- --- $2,400,000 ---
Warden High
Pressure
Reinforcement, WA
$100,000 $2,950,000 $2,950,000 --- ---

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 177 of 184
Table 8.2 shows city gate stations identified as possibly over utilized or under capacity.
Estimated cost, year and the plan to remediate the capacity concern are shown.
These projects are preliminary estimates of timing and costs of city gate station upgrades.
The scope and needs of each project generally evolve with new information requiring
ongoing reassessment. Actual solutions may differ due to differences in actual growth
patterns and/or construction conditions that differ from the initial assessment.

The city gate station projects in Table 8.2 are periodically reevaluated to determine if
upgrades need to be accelerated or delayed.

Those assigned a TBD year have relatively small capacity constraints, and thus will be
monitored. There are no plans to rebuild or upgrade these city gate stations at this time.

Table 8.2 City Gate Station Upgrades
Location Gate Station Project to Remediate Cost Year
Colton, WA Colton #316 TBD - TBD
Medford, OR Medford #2431 TBD TBD
Pullman, WA Pullman #350 TBD - TBD
Roseburg, OR Melrose #2608 TBD - TBD
Sprague, WA Sprague #117 TBD - TBD
Sutherlin, OR Sutherlin #2626 TBD - TBD

Conclusion
Avista’s goal is to maintain its natural gas distribution systems reliably and cost effectively
to deliver natural gas to every customer. This goal relies on modeling to increase the
capacity and reliability of the distribution system by identifying specific areas that may
require changes. The ability to meet the goal of reliable and cost-effective natural gas
delivery is enhanced through localized distribution planning, which enables coordinated
targeting of distribution projects responsive to customer growth patterns.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 178 of 184
9: Action Plan

The purpose of an action plan is to position Avista to provide the best cost/risk resource portfolio
and to support and improve IRP planning. The Action Plan identifies needed supply and
demand side resources and highlights key analytical needs in the near term. It also highlights
essential ongoing planning initiatives and natural gas industry trends Avista will monitor as a
part of its planning processes.

2017-2018 Action Plan Review

Avista’s 2020 IRP will contain an individual measure level for dynamic DSM program
structure in its analytics. In prior IRP’s, it was a deterministic method based on based on
Expected Case assumptions. In the 2020 IRP, each portfolio will have the ability to select
conservation to meet unserved customer demand. Avista will explore methods to enable
a dynamic analytical process for the evaluation of conservation potential within individual
portfolios.
Result – Result- Avista discussed with Energy Trust of Oregon. It was decided that we
will continue to use Energy Trust’s current modeling protocols to run scenarios analyses
for the Conversation Potential Assessment (CPA). This decision enables the greatest
alignment between what Energy Trust expects they will be able to achieve under different
policy scenarios. These scenarios may include modeling using differential assumptions
such as: a) different avoided costs and b) accelerated and decelerated program uptake
scenarios. This also allows Energy Trust to include measures in the CPA that are offered
through Energy Trust programs under cost-effectiveness exceptions granted by the
OPUC under UM-551 guidelines. These CPA practices coincide well with the capabilities
of the software that Avista is using for other IRP modeling purposes. Consequently,
Avista has chosen not to further investigate dynamic DSM program structure modeling in
its analytics. Based on Avista’s efforts with ETO, it was decided to forgo the ability to
analyze DSM in Washington and Idaho due to any disparities that may occur from the
separation of analysis types.

Work with Staff to get clarification on types of natural gas distribution system analyses for
possible inclusion in the 2020 IRP.
Result - Any large natural gas distribution system analysis will be included in all future
IRP’s against system resources where necessary.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 179 of 184
Work with Staff to clarify types of distribution system costs for possible inclusion in our
avoided cost calculation.
Result – Distribution system costs are included in the avoided cost calculation and will
be included in all future IRP documents.
Revisit coldest on record planning standard and discuss with TAC for prudency.
Result – Avista has changed its weather planning standard based on a probability of
occurrence based on each weather planning location. The current methodology uses the
most recent 30 years of weather and the coldest day of each year combined with a 99%
probability of a weather event occurring.
Provide additional information on resource optimization benefits and analyze risk
exposure.
Result – Chapter 4 – Supply Side Resources has been expanded to not only add in
resource optimization benefits and risk exposure, but also includes additional details of
Avista’s natural gas hedging program
DSM—Integration of ETO and AEG/CPA data. Discuss the integration of ETO and
AEG/CPA data as well as past program(s) experience, knowledge of current and
developing markets, and future codes and standards.
Result – The integration of Avista’s CPA providers is discussed in Chapter 3 – Demand
Side Management.
Carbon Costs – consult Washington State Commission’s Acknowledgement Letter
Attachment in its 2017 Electric IRP (Docket UE-161036), where emissions price modeling
is discussed, including the cost of risk of future greenhouse gas regulation, in addition to
known regulations.
Result – The social cost of carbon is used in the Expected Scenario for the State of
Washington.
Avista will ensure Energy Trust of Oregon (ETO) has sufficient funding to acquire therm
savings of the amount identified and then approved by the OPUC and ETO Board.
Result – The ETO has received the necessary funding to acquire therm savings as
identified and then approved by the OPUC and ETO Board.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 180 of 184
Regarding high pressure distribution or city gate station capital work, Avista does not
expect any supply side or distribution resource additions to be needed in our Oregon
territory for the next four years, based on current projections. However, should conditions
warrant that capital work is needed on a high-pressure distribution line or city gate station
in order to deliver safe and reliable services to our customers, the Company is not
precluded from doing such work. Examples of these necessary capital investments
include the following:
• Natural gas infrastructure investment not included as discrete projects in IRP
o Consistent with the preceding update, these could include system
investment to respond to mandates, safety needs, and/or maintenance of
system associated with reliability
▪ Including, but not limited to Aldyl A replacement, capacity
reinforcements, cathodic protection, isolated steel replacement, etc.
• Anticipated PHMSA guidance or rules related to 49 CFR Part §192 that will likely
require additional capital to comply
o Officials from both PHMSA and the AGA have indicated it is not prudent for
operators to wait for the federal rules to become final before improving their
systems to address these expected rules.
▪ Construction of gas infrastructure associated with growth
▪ Other special contract projects not known at the time the IRP was
published
• Other non-IRP investments common to all jurisdictions that are ongoing, for
example:
o Enterprise technology projects & programs
o Corporate facilities capital maintenance and improvements

An updated table 8.1 for those distribution projects in Oregon:
Location Gate Station Project to Remediate Cost Year
Klamath
Falls, OR Klamath Falls #2703 TBD - 2023+
Sutherlin, OR Sutherlin #2626 TBD - 2023+

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 181 of 184
Result – Large High-pressure distribution and City Gas projects did not occur since the
2018 IRP. Quarterly updates will continue to occur with Oregon Staff to ensure any
change in projects is known along with reasons for any major changes in expected capital
expenditures.

Avista will work with members of the OPUC to determine an alternative stochastic
approach to Monte Carlo analysis prior to Avista’s 2020 IRP and share any
recommendations with the TAC members.
Result – Avista and the OPUC agreed on a 1,000 draw minimum in all scenarios and
were performed to this standard in all stochastic simulations in the current IRP.

2021-2022 Action Plan

New Activities for the 2023 IRP
1. Further model carbon reduction in Oregon and Washington
2. Investigate new resource plan modeling software and integrate Avista’s system
into software to run in parallel with Sendout
3. Model all requirements as directed in Executive Order 20-04
4. Avista will ensure Energy Trust (ETO) has sufficient funding to acquire therm
savings of the amount identified and approved by the Energy Trust Board.
5. Explore the feasibility of using projected future weather conditions in its design day
methodology.
6. Regarding high pressure distribution or city gate station capital work, Avista does
not expect any supply side or distribution resource additions to be needed in our
Oregon territory for the next four years, based on current projections. However,
should conditions warrant that capital work is needed on a high-pressure
distribution line or city gate station in order to deliver safe and reliable services to
our customers, the Company is not precluded from doing such work. Examples of
these necessary capital investments include the following:
• Natural gas infrastructure investment not included as discrete projects in IRP
– Consistent with the preceding update, these could include system
investment to respond to mandates, safety needs, and/or maintenance
of system associated with reliability
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 182 of 184
•Including, but not limited to Aldyl A replacement, capacity
reinforcements, cathodic protection, isolated steel replacement,
etc.
–Anticipated PHMSA guidance or rules related to 49 CFR Part §192 that
will likely require additional capital to comply
•Officials from both PHMSA and the AGA have indicated it is not
prudent for operators to wait for the federal rules to become final
before improving their systems to address these expected rules.
–Construction of gas infrastructure associated with growth
–Other special contract projects not known at the time the IRP was
published
•Other non-IRP investments common to all jurisdictions that are ongoing, for
example:
–Enterprise technology projects & programs
–Corporate facilities capital maintenance and improvements
Ongoing Activities
•Continue to monitor supply resource trends including the availability and price of
natural gas to the region, LNG exports, methanol plants, supply and market
dynamics and pipeline and storage infrastructure availability.
•Monitor availability of resource options and assess new resource lead-time
requirements relative to resource need to preserve flexibility.
•Meet regularly with Commission Staff to provide information on market activities
and significant changes in assumptions and/or status of Avista activities related to
the IRP or natural gas procurement practices.
•Appropriate management of existing resources including optimizing underutilized
resources to help reduce costs to customers.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 183 of 184
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3, Page 184 of 184
2021 Natural Gas
Integrated Resource Plan
Appendices
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 1 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 2 of 794
Safe Harbor Statement

This document contains forward-looking statements. Such statements are subject to a
variety of risks, uncertainties and other factors, most of which are beyond the Company’s
control, and many of which could have a significant impact on the Company’s operations,
results of operations and financial condition, and could cause actual results to differ
materially from those anticipated.

For a further discussion of these factors and other important factors, please refer to the
Company’s reports filed with the Securities and Exchange Commission. The forward-
looking statements contained in this document speak only as of the date hereof. The
Company undertakes no obligation to update any forward-looking statement or
statements to reflect events or circumstances that occur after the date on which such
statement is made or to reflect the occurrence of unanticipated events. New risks,
uncertainties and other factors emerge from time to time, and it is not possible for
management to predict all of such factors, nor can it assess the impact of each such factor
on the Company’s business or the extent to which any such factor, or combination of
factors, may cause actual results to differ materially from those contained in any forward-
looking statement.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 3 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 4 of 794
TABLE OF CONTENTS: APPENDICES
Appendix 0.1 TAC Member List ..................................................................... Page 1
0.2 Comments and Responses to the 2021 IRP ....................................... 2
Appendix 1.1 Avista Corporation 2021 Natural Gas IRP Work Plan ......................... 9
1.2 IRP Guideline Compliance Summaries ............................................ 12
Appendix 2.1 Economic Outlook and Customer Count Forecast ............................ 27
2.2 Customer Forecasts by Region........................................................ 45
2.3 Demand Coefficient Calculations ..................................................... 87
2.4 Heating Degree Day Data ................................................................ 91
2.5 Demand Sensitivities and Demand Scenarios ................................ 101
2.6 Demand Forecast Sensitivities and Scenarios Descriptions ............ 103
2.7 Annual Demand, Avg Day & Peak Day Demand (Net of DSM)........ 108
2.8 Demand Before and After DSM...................................................... 112
2.9 Detailed Demand Data .................................................................. 117
Appendix 3.1 Avista Gas CPA Report Final ......................................................... 127
3.2 Environmental Externalities ........................................................... 131
Appendix 4.1 Current Transportation/Storage Rates and Assumptions ................ 225
Appendix 5.1 Renewable Resource Development and Procurement Tree............ 227
Appendix 6.1 Monthly Price Data by Basin .......................................................... 233
6.2 Weighted Average Cost of Capital ................................................. 242
6.3 Supply Side Resource Options ...................................................... 243
6.4 Avoided Costs Detail ..................................................................... 244
Appendix 7.1 High Growth Case ........................................................................ 265
7.2 Peak Day Demand Table …........................................................... 267
Appendix 8.1 Distribution System Modeling…………………………………………...275
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 5 of 794
Appendix 8.2 Distribution within the IRP……………………………………………279
TAC Meeting #1…………………… ....................................................... 281
TAC Meeting #2 .................................................................................. 379
TAC Meeting #2.5……………………………………………………………..481
TAC Meeting #3 .................................................................................. 527
TAC Meeting #4 .................................................................................. 672

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 6 of 794
APPENDIX 0.1: TAC MEMBER LIST
Organization Representatives
Applied Energy Group Kenneth Walter
Avista
Terrence Browne Jody Morehouse
Amanda Ghering Tom Pardee
Ryan Finesilver Michael Brutocao
Grant Forsyth Jason Thackston
James Gall Jaime Majure
Justin Dorr Michael Whitby
John Lyons Shawn Bonfield
Lisa McGarity Jeff Webb
Biomethane, LLC Kathlyn Kinney
Cascade Natural Gas Company Ashton Davis Brian Robertson
Mark Sellers-Vaughn
Citizens Utility Board of Oregon Sudeshna Pal Will Gehrke
Energy Trust of Oregon Peter Schaffer Spencer
Moersfelder
Ted Light
Fortis Ken Ross
Idaho Conservation League Dainee Gibson-
Webb
Idaho Public Utility Commission
Donn English Kevin Keyt
Terri Carlock Mike Louis
Joseph Terry Rick Keller
Intermountain Gas Raycee Thompson Lori Blattner
Dave Swenson
Northwest Energy Coalition Amy Wheeless
Northwest Gas Association Dan Kirschner
Northwest Natural Gas Tammy Linver
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 7 of 794

Northwest Power and Conservation Council Steve Simmons

Oregon Public Utility Commission Anna Kim Kim Herb

Washington State Department of
Commerce
Peter Moulton Greg Nothstein
Chuck Murray

Washington State Office of the Attorney General Shay Bauman Corey J Dahl
Chuck Murray

Washington Utilities and Transportation Commission
Jennifer Snyder Deborah Reynolds
Andrew Rector Steve Johnson

APPENDIX 0.2: COMMENTS AND RESPONSES TO 2021 DRAFT INTEGRATED
RESOURCE PLAN
The following table summarizes the significant comments on our DRAFT as submitted by TAC members and
Avista’s responses. This IRP produced reduced forecasted demand scenarios and no near term resource needs
even in our most robust demand scenario. We appreciate the time and effort invested by all our TAC members
throughout the IRP process. Many good suggestions have been made and we have incorporated those that
enhance the document.

Document Reference Comment / Question Avista Response
Chapter 5 For upstream methane emissions, Avista uses a
global warming potential (GWP) factor that was
calculated based on the International Panel on
Climate Change’s Assessment Report 5 (IPCC
AR5), which Staff prefers over older analyses.
Avista uses the upstream methane leakage
factor of 0.77 percent for Canadian natural gas,
and uses 1.0 percent for the U.S. Rockies natural
gas factor. Given that this U.S. Rockies natural gas emissions factor is significantly lower than any of the factors analyzed by the NWPCC in its analysis of upstream natural gas emissions, Staff recommends the Final IRP explain why the factor is appropriate.
Added supplimental language to
Chapter 5
Chapter 7 Consider effects of policy trends towards
electrification on both the electric and natural gas
systems.
Included supplemental language
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 8 of 794
Chapter 2 Explain the new design day methodology,
providing a more detailed narrative.
Updated within Chapter 2
Chapter 2 Further explain why the new design day standard is now the most appropriate one. Updated within Chapter 2
Chapter 9 Explore the feasibility of using projected future
weather conditions in its design day
methodology, rather than relying exclusively on
historic data.
added to Action Plan
Appendix 7.2 Include details of RNG cost assumptions in the
appendices.
Included in Appendix 7.2
Appendix 7.2 Use any up-to-date cost data that is available to model potential RNG resources. Avista will use the most recent data available where details are verified, reasonable and sufficient enough for cost determination in all resources Avista 2021 Electric IRP Avista’s Draft 2021 IRP, p11, provides some explanation for factors that could drive future natural gas demand. While Avista does not anticipate any increase in demand from the traditional residential and commercial customer classes, the Company expects growing demand from electric utilities in terms of natural gas back up for solar and wind technologies. CUB is aware that electric utilities serving the Pacific Northwest like, Portland General Electric and PacifiCorp do not have plans to build new gas plants in the long-term. Idaho Power targets for
100% clean energy by 2045. BC Hydro’s Clean Power 2040 mandate includes reduction of GHG emissions through clean electricity. CUB would therefore like to see some discussion in the IRP that could substantiate the claim that electric utilities in the Pacific Northwest region are increasingly becoming reliant on gas plants as backups for their renewable generation resources.
Please refer to the Avista 2021 Electric IRP for peaking needs from natural gas plants as summarized in it's Preferred Resource Strategy (PRS). The Wood Mackenzie material shown during TAC 2 on August 6, 2020 will provide a high level summary of expected need in the Pacific Northwest, which dispite the massive expected buildout of renewable resources, less than half of the natural gas leaves the forecast. On a national level the forecast for the next 20 years remains mostly unchanged in spite of the new electric clean resources. In this case, growing demand does not infer new natural gas plants, just continued demand to meet electric capacity requirements.
Chapter 2, 5 &
7
CUB realizes that Carbon price sensitivities are
designed around Oregon and Washington’s
carbon policy futures as Idaho does not
contemplate having a carbon policy in near
future. Hence Avista assumes a carbon cost of $0 for Idaho and other carbon price ranges for Oregon and Washington. CUB suggests that for a long-term planning purpose, Avista should look at a price range for Idaho with a lower limit of $0 and set a positive dollar amount as upper limit, like it has for Oregon and Washington. CUB would like to cite Idaho Power’s 2019 IRP in which the utility considers four carbon cost scenarios, namely,
Chapter 2 contains the
sensitivities to a high, expected
and low price as compared to
the reference case for all
jurisdictions. The expected carbon price considers any known policy or direction by state or federal entities that may help indicate a carbon price. In the event there is no policy, like Idaho, formulating a potential price indicator is problematic leading Avista to measure the bounds for risk vs. a specific policy as done through the
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 9 of 794
scenarios of high growth and low prices and low growth and high prices. Electric utilities can use shadow pricing or inferred pricing to determine when plants are still cost effective. Natural gas, mostly, uses the single fossil commodity to determine demand. Avista will continue to look for ways to value carbon and include where appropriate.
Chapter 2, 5, 7 Zero Cost – no state or federal tax or fee on carbon emissions), A low price of carbon of $0 is assumed for all 3 jurisdictions in the High Growth and Low Prices case to measure no carbon policy.
Chapter 2, 5, 7 Planning Carbon – Based on Wood Mckenzie’s
forecasts, starting with $2/ton in 2028 and goes
up to $22/ton by the end of the planning period,
A Wood Mackenzie carbon
assumption was put in place to
measure Oregon's cap and
reduce future
Chapter 2, 5, 7 Generational Carbon – Based on EPA’s estimated of social cost of carbon, starting at $55.73/ton starting in 2020 and increasing to $101.16/ton by the end of the planning period, and,
This is assumed for WA in the Expected Case
Chapter 2, 5, 7 High Carbon – Based on California Energy
Commission’s Integrated Energy Policy Report only for federal programs. Carbon costs under this scenario are assumed to start at $28.65/ton in 2022 increasing to $107.87 by the end of the IRP planning horizon. CUB believes using a carbon price range for Idaho will address local, state and federal environment policy related uncertainties for the system as a whole for the planning period.
high carbon costs are included for all jurisdictions to measure the upper limits of carbon prices in the Low Growth and High Prices
Chapter 7 Avista’s Electric IRP includes a natural gas to
electricity switching scenario. CUB is wondering
why this scenario analysis was not also a part of
the natural gas IRP. Recently there have been
proposals to phase out gas space and water
heating in Washington state. Around forty
communities in California have imposed a ban on
natural gas heating in new buildings. Avista’s
service territory in Southern Oregon is well suited
in terms of climate for electrification of heating
load. CUB suggests that Avista explore a No
Growth scenario for its long-term demand
forecast.
A write up is included in Chapter
7. Avista will explore a no
growth scenario in the 2023
Avista Natural Gas IRP
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 10 of 794
Chapter 7 Staff is particularly interested in understanding
how different RNG resources were compared for
selection in the alternate scenario.
Resources were compared
against all resource modeled
options which can be viewed in
Chapter 7. The options account
for all estimated costs to build
and maintain the facility and
account for the cost of carbon
based on the carbon intensity
savings by source
Chapter 8 With regard to demand response (Guideline 7),
the Company mentions a single project on page
165. Staff would like to see more information about demand response as a demand-side option in the final IRP, both as a system resource and its potential to offset distribution upgrades.
The high pressure projects
mentioned on page 165 were
identified after comprehensive load study analyses. Each analysis uses 18-24 months of historical customer billing history, so any DSM or energy ef f iciency measures adopted by customers are reflected in the loads of the analysis. The projects listed reflect current shortfalls on the distribution system. These shortfalls or deficiencies are also too large to be eliminated or even mitigated by DSM or energy efficiency measures. Since most of these projects will be completed over more than one year, Avista will use subsequent load studies to determine if there is a change in the necessity of a project, and then revise or defer accordingly.
Chapter 5 Regarding Environmental Costs (Guideline 8),
Staff appreciates the Company’s analysis of a
portfolio under the Carbon Reduction scenario,
and the Company’s consideration of creative
solutions to compete as a buyer with California’s
Low Carbon Fuel Standard market. Staff has
questions about the assumptions leading to a
portfolio of all dairy RNG and will like to see more
discussion about how realistic that portfolio is,
considering both total accumulation and the
timing of additions over 20 years.
Unlike WWTP and landfills, for
example, the ability to move
livestock and create the product
of methane capture seems
reasonable. The quantity of
these products supply needed is
high. The overall potential of
this is unknown and so based on
the plan to go after the next
cheapest resource the product
potentials will be better known
once carbon pricing, targets and
deadlines are clear. This is
mostly illustrative in nature and
future potential must be
estimated by state to have a
realistic guideline in place for
obtaining these goals.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 11 of 794
Chapter 5 In addition to the carbon reduction alternate
portfolio, Staff will also consider whether the
preferred portfolio and action plan are consistent
with Oregon policies. Staff acknowledges that the
Company is awaiting additional guidance on how
to implement EO 20-04 and understands the
Company is prepared to comply by guidance
provided, however Staff looks forward to
understanding the extent to which the preferred
portfolio is consistent with current Oregon policy,
including EO 20-04. Further, Staff is preparing to
engage with stakeholders on the implementation
feasibility and impact of the IRP related activities
identified in OPUC EO 20-04 work plan section
1.1. Staff suggests that the company be familiar
with this section and be prepared to discuss
metrics the Company could provide to track and
forecast GHG emissions and strategies to reduce
emissions to be compliant with EO 20-04.
The company is engaged in
dialogue and meetings
surrounding the effort around EO
20-04 and will implement the
necessary strategies to reduce
emissions.
Chapter 5, 6, 7 With regards to Guideline 10 (Multi-State Utilities), Staff also has questions about how policies across states interact, particularly for RNG. Staff would like to understand the assumptions the Company is using regarding the interaction of RNG policies in Washington and Oregon, and any system-wide strategies being considered.
Resources are solved on a system basis for least cost supply. In the case where Oregon and Washington may both be requiring in state emissions reduction supply sources, Avista modeled these resources directly into the demand zones. This will also help to correctly allocate costs by jurisdiction Chapter 2, 5, 6, 7 1. Staff made a number of recommendations for potential improvements to the demand forecast. Staff has identified this topic as a key area of focus, particularly in terms of forecasted customer counts and usage per customer. Many of the recommendations relate to improving the modeling of potential carbon policy. For example, although the Company describes on page 11 that
“Avista does not anticipate traditional residential and commercial customers will provide increased
growth in demand,” even in its low growth scenario, the Company is forecasting
A scenario with reduced demand could be the carbon reduction scenario in the 2021 natural gas IRP. In future IRP's we will consider a declining customer growth scenario. The Low Growth & High Prices scenarios is the best indicator for where Avista currently sees a reduced customer set paired with DSM to offset demand. The Carbon Reduction was included for our Washington service territory with the results and demand loss summarized in Chapter 7. If a similar load loss to electrification
were to occur in Oregon, the
impact to Avista would strictly be
a loss of natural gas demand.
The impacts to local electric
utilities would need to be
quantified by the utilities in each
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 12 of 794
of these service areas. The
costs to run natural gas service
for those remaining customers
would be held by fewer and
fewer customers meaning their
rates would continue to go up.
Chapter 2 –
Appendix 2.6
2. Staff also recommended that the Company
explore a large-scale supply interruption
scenario, and the role of storage in such a
situation. This scenario does not appear to be
addressed in the draft IRP.
A large scale supply interruption
and its impacts to Avista's
natural gas system can be seen
in Chapter 2. In the cases of a
100% loss of supply or even
50% loss of supply at AECO, JP,
SUMAS, or Rockies trading
points puts an unserved in the
first or second year of planning.
Based on these sensitivities it
became evident as to the
extreme predictions and
outcomes of these supply basin
outages, so Avista chose not to
run a specified scenario.
Chapter 8 Staff is interested in better understanding the
lack of anticipated distribution system upgrades.
Staff would like to learn more about the certainty
of this prediction and what sorts of upgrades the
Company is excluding (i.e., is the Company
completely foregoing all distribution investments
for the next two years, or does the exclusion of
distribution projects in the Company’s IRP reflect
a lack of larger investments?) the Company
should include information the Company relied
upon to come to this conclusion in its IRP filing.
Please see Chapter 8 Table 8.2.
Also, The city gate station
projects in Table 8.2 are
periodically reevaluated to
determine if upgrades need to
be accelerated or delayed.
Those assigned a TBD year
have relatively small capacity
constraints, and thus will be
monitored. There are no plans
to rebuild or upgrade these city
gate stations at this time.
Chapter 5, 6, 7 Staff is interested in the interaction between resources, policies, and plans between the
Company’s Washington and Oregon territories.
Carbon Reduction scenario for specifics on the interaction between policies, resources and
plans between our WA and OR
territories

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 13 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 14 of 794
APPENDIX 1.1: AVISTA CORPORATION 2021 NATURAL GAS INTEGRATED RESOURCE PLAN WORK PLAN
IRP WORK PLAN REQUIREMENTS
Section 480-90-238 (4), of the natural gas Integrated Resource Plan (“IRP”) rules, specify requirements for
the IRP Work Plan:
Not later than twelve months prior to the due date of a plan, the utility must provide a work
plan for informal commission review. The work plan must outline the content of the
integrated resource plan to be developed by the utility and the method for assessing
potential resources.
Additionally, Section 480-90-238 (5) of the WAC states:
The work plan must outline the timing and extent of public participation.
OVERVIEW
This Work Plan outlines the process Avista will follow to complete its 2023 Natural Gas IRP by April 1,
2023. Avista uses a public process to obtain technical expertise and guidance throughout the planning
period via Technical Advisory Committee (TAC) meetings. The TAC will be providing input into
assumptions, scenarios, and modeling techniques.
PROCESS
The 2021 IRP process will be similar to that used to produce the previously published plan. Avista will use
SENDOUT® (a PC based linear programming model widely used to solve natural gas supply and
transportation optimization questions) to develop the risk adjusted least-cost resource mix for the 20 year
planning period.
This plan will continue to include demand analysis, demand side management and avoided cost
determination, existing and potential supply-side resource analysis, resource integration and alternative
sensitivities and scenario analysis.
Additionally, Avista intends to incorporate action plan items identified in the 2021 Natural Gas IRP
including more detailed demand analysis regarding use per customer, demand side management results and
possible price elastic responses to evolving economic conditions, an updated assessment of conservation
potential in our service territories, consideration of alternate forecasting methodologies, and the changing
landscape of natural gas supply (i.e. shale gas, Canadian exports, and US LNG exports) and its implications
to the planning process. Further details about Avista’s process for determining the risk adjusted least-cost
resource mix is shown in Exhibit 1.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 15 of 794
TIMELINE
The following is Avista’s 2021 Natural Gas IRP timeline:

TAC 1: Wednesday, June 17, 2020: TAC meeting expectations, 2020 IRP process and
schedule, energy efficiency update, actions from 2018 IRP, and a Winter of 2018-2019
review. Procurement Plan and Resource Optimization benefits. fugitive Emissions, Weather
Analysis, Weather Planning Standard

TAC 2 (Dual Meeting with Power side): Thursday, August 6, 2020: Market Analysis,
Price Forecasts, Cost Of Carbon, demand forecasts and CPA results from AEG,
Environmental Policies

TAC 3: Wednesday, September 30, 2020: Distribution, Avista’s current supply-side
resources overview, supply side resource options, renewable resources, SENDOUT
overview, sensitivities and portfolio selection modeling.

TAC 4: Wednesday, November 18, 2020: Review assumptions and action items, final
modeling results, portfolio risk analysis and 2020 Action Plan.

TAC 5: February 2021: TAC final review meeting (if necessary)

Avista’s TENTATIVE 2023 Natural Gas IRP timeline:
Major Milestone Date Topics
TAC 1 Nov-2022 Use per customer, Policy, 2021 Action Item
Review, price elasticity
TAC 2 Mar-2022 Customer Forecast, price forecast
TAC 3 Apr-2022 sensitivities, distribution, model overview
TAC 4 Jun-2022 Renewable Resources, Supply Side
Resources, Demand Side Resources (CPA)
TAC 5 Jul-2022 Results / Stochastics, Action Items
Write IRP Draft Sep-2022
Draft Feedback Due Oct-2022
File Dec-2022

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 16 of 794
EXHIBIT 1: AVISTA’S 2021 NATURAL GAS IRP MODELING PROCESS

Demand Forecast by Area and Class
Customer counts
Use per customer
Elasticity
Gas Prices
Basis differential
Volatility
Seasonal Spreads
Existing Supply-Side Resources
Costs
Operational Characteristics
Carbon Intensity
Weather
20-year NOAA average by area plus
Peak Day weather Standard
Optimization
Run

Identify when and where
deficiencies occur in the 20-
year planning period.
Optimization
Run

Solve for deficiencies and
incorporate those into the
least costs resource mix
for the 20-year period.
Determine Base
Case Scenario
Avoided Cost
Determination Compile Data and Write
the IRP Document.
Key Considerations
•Resource Cost
•Peak vs. Base Load
•Lead Time Requirements
•Resource Usefulness
•“Lumpiness” of Resource Options
Sensitivity/Scenario
Analysis
•Customer
•Supply
interruptions
•Counts
•Use per
customer
•DSM
•Monte Carlo
•Etc.
Gate Station
Analysis
Price Curve
Analysis
Planning
Standard Review
Enter all Future Resource
Options:
Supply-Side
Demand-Side Resources
•Assess DSM resource options

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 17 of 794
APPENDIX 1.2: WASHINGTON PUBLIC UTILITY COMMISSION IRP POLICIES AND
GUIDELINES – WAC 480-90-238
Rule Requirement Plan Citation
WAC 480-90-238(4) Work plan filed no later than 12
months before next IRP due date.
Work plan submitted to the WUTC
on August 31, 2019, See attachment to this Appendix 1.1.
WAC 480-90-238(4) Work plan outlines content of IRP. See work plan attached to this Appendix 0.1. WAC 480-90-238(4) Work plan outlines method for assessing potential resources. (See LRC analysis below)
See Appendix 1.1.
WAC 480-90-238(5) Work plan outlines timing and extent of public participation. See Appendix 1.1.
WAC 480-90-238(4) Integrated resource plan submitted
within two years of previous plan.
Last Integrated Resource Plan was
submitted on August 31, 2018
WAC 480-90-238(5) Commission issues notice of public hearing after company files plan for review.
TBD
WAC 480-90-238(5) Commission holds public hearing. TBD
WAC 480-90-238(2)(a) Plan describes mix of natural gas supply resources. See Chapter 4 on Supply Side Resources
WAC 480-90-238(2)(a) Plan describes conservation supply. See Chapter 3 on Demand Side Resources
WAC 480-90-238(2)(a) Plan addresses supply in terms of
current and future needs of utility and ratepayers.
See Chapter 4 on Supply Side
Resources and Chapter 6 Integrated Resource Portfolio WAC 480-90-238(2)(a)&(b) Plan uses lowest reasonable cost (LRC) analysis to select mix of resources.
See Chapters 3 and 4 for Demand and Supply Side Resources. Chapters 6 and 7 details how Demand and Supply come
together to select the least cost/best risk portfolio for ratepayers. WAC 480-90-238(2)(b) LRC analysis considers resource costs. See Chapters 3 and 4 for Demand and Supply Side Resources. Chapters 6 and 7 details how Demand and Supply come together to select the least cost/best risk portfolio for
ratepayers.
WAC 480-90-238(2)(b) LRC analysis considers market-volatility risks. See Chapter 4 on Supply Side Resources
WAC 480-90-238(2)(b) LRC analysis considers demand side uncertainties. See Chapter 2 Demand Forecasting WAC 480-90-238(2)(b) LRC analysis considers resource effect on system operation. See Chapter 4 and Chapter 6
WAC 480-90-238(2)(b) LRC analysis considers risks imposed on ratepayers. See Chapter 4 procurement plan section. We seek to minimize but
cannot eliminate price risk for our customers.
WAC 480-90-238(2)(b) LRC analysis considers public
policies regarding resource preference
See Chapter 2 demand scenarios
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 18 of 794
adopted by Washington state or federal government.
WAC 480-90-238(2)(b) LRC analysis considers cost of risks associated with environmental effects
including emissions of carbon dioxide.
See Chapters 2 and 6 on demand scenarios and Integrated Resource
Portfolio
WAC 480-90-238(2)(b) LRC analysis considers need for security of supply. See Chapter 4 on Supply Side Resources
Rule Requirement Plan Citation
WAC 480-90-238(2)(c) Plan defines conservation as any reduction in natural gas consumption
that results from increases in the ef f iciency of energy use or distribution.
See Chapter 3 on Demand Side Resources
WAC 480-90-238(3)(a) Plan includes a range of forecasts of
future demand.
See Chapter 2 on Demand
Forecast
WAC 480-90-238(3)(a) Plan develops forecasts using methods that examine the effect of economic forces on the consumption of natural gas.
See Chapter 2 on Demand Forecast
WAC 480-90-238(3)(a) Plan develops forecasts using methods that address changes in the number, type and efficiency of natural
gas end-uses.
See Chapter 2 on Demand Forecast
WAC 480-90-238(3)(b) Plan includes an assessment of commercially available conservation,
including load management.
See Chapter 3 on Demand Side Management including demand
response section.
WAC 480-90-238(3)(b) Plan includes an assessment of currently employed and new policies and programs needed to obtain the conservation improvements.
See Chapter 3 and Appendix 3.1.
WAC 480-90-238(3)(c) Plan includes an assessment of conventional and commercially available nonconventional gas
supplies.
See Chapter 4 on Supply Side Resources
WAC 480-90-238(3)(d) Plan includes an assessment of opportunities for using company-owned or contracted storage.
See Chapter 4 on Supply Side Resources
WAC 480-90-238(3)(e) Plan includes an assessment of pipeline transmission capability and reliability and opportunities for
additional pipeline transmission resources.
See Chapter 4 on Supply Side Resources
WAC 480-90-238(3)(f) Plan includes a comparative evaluation of the cost of natural gas purchasing
strategies, storage options, delivery resources, and improvements in conservation using a consistent method to calculate cost-effectiveness.
See Chapter 3 on Demand Side Resources and Chapter 4 on
Supply Side Resources
WAC 480-90-238(3)(g) Plan includes at least a 10 year long-range planning horizon. Our plan is a comprehensive 20 year plan.
WAC 480-90-238(3)(g) Demand forecasts and resource evaluations are integrated into the long range plan for resource acquisition.
Chapter 6 Integrated Resource Portfolio details how demand and supply come together to form the least cost/best risk portfolio. WAC 480-90-238(3)(h) Plan includes a two-year action plan that implements the long range plan. See Section 9 Action Plan
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 19 of 794
WAC 480-90-238(3)(i) Plan includes a progress report on the implementation of the previously filed
plan.
See Section 9 Action Plan
WAC 480-90-238(5) Plan includes description of consultation with commission staff. (Description not required)
See Section 1 Introduction
WAC 480-90-238(5) Plan includes description of completion of work plan. (Description not required) See Appendix 1.1.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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APPENDIX 1.2: IDAHO PUBLIC UTILITY COMMISSION IRP POLICIES AND GUIDELINES – ORDER NO. 2534
DESCRIPTION OF REQUIREMENT FULLFILLMENT OF REQUIREMENT
1 Purpose and Process. Each gas utility regulated by the Idaho Public Utilities Commission with retail sales of more than 10,000,000,000 cubic feet in a calendar year (except gas utilities doing business in Idaho that are regulated by contract with a regulatory commission of another State) has the
responsibility to meet system demand at least cost to the utility and its ratepayers. Therefore, an ‘‘integrated resource plan’’ shall be developed by each gas utility subject to this rule.
Avista prepares a comprehensive 20 year Integrated Resource Plan every two years. Avista will be filing its 2023 IRP on or before April 1, 2023.
2 Definition. Integrated resource planning.
‘‘Integrated resource planning’’ means planning by the use of any standard, regulation, practice, or policy to undertake a systematic comparison between demand-side management measures and the supply of gas by a gas utility to minimize life-
cycle costs of adequate and reliable utility services to gas customers. Integrated resource planning shall take into account necessary features for
system operation such as diversity, reliability, dispatchability, and other factors of risk and shall treat demand and supply to gas consumers on a consistent and integrated basis.
Avista's IRP brings together dynamic
demand forecasts and matches them against demand-side and supply-side resources in order to evaluate the least cost/best risk portfolio for its core customers. While the primary focus has been to ensure customer's
needs are met under peak or design weather conditions, this process also evaluates the resource portfolio under normal/average
operating conditions. The IRP provides the framework and methodology for evaluating Avista's natural gas demand and resources.
3 Elements of Plan. Each gas utility shall submit to the Commission on a biennial basis an integrated
resource plan that shall include:
Filing extension approved for 2021 IRP to be filed on or before April 1, 2021. The last IRP
was filed on August 31, 2018.
A range of forecasts of future gas demand in firm and interruptible markets for each customer class
for one, five, and twenty years using methods that examine the effect of economic forces on the consumption of gas and that address changes in the number, type and efficiency of gas end-uses.
See Chapter 2 - Demand Forecasts and Appendix 2 et.al. for a detailed discussion of
how demand was forecasted for this IRP.
An assessment for each customer class of the
technically feasible improvements in the efficient use of gas, including load management, as well as the policies and programs needed to obtain the efficiency improvements.
See Chapter 3 - Demand Side
Management and DSM Appendices 3 et.al. for detailed information on the DSM potential evaluated and selected for this IRP and the operational implementation process.
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An analysis for each customer class of gas supply options, including: (1) a projection of spot market versus long-term purchases for both firm and
interruptible markets; (2) an evaluation of the opportunities for using company-owned or contracted storage or production; (3) an analysis of prospects for company participation in a gas futures market; and (4) an assessment of opportunities for
access to multiple pipeline suppliers or direct purchases from producers.
See Chapter 4 - Supply-Side Resources for details about the market, storage, and pipeline transportation as well as other
resource options considered in this IRP. See also the procurement plan section in this same chapter for supply procurement strategies.
A comparative evaluation of gas purchasing options and improvements in the efficient use of gas based on a consistent method for calculating
cost-effectiveness.
See Methodology section of Chapter 3 - Demand-Side Resources where we describe our process on how demand-side
and supply-side resources are compared on par with each other in the SENDOUT®
model. Chapter 3 also includes how results from the IRP are then utilized to create operational business plans. Operational implementation may differ from IRP results due to modeling assumptions.
The integration of the demand forecast and resource evaluations into a long-range (e.g.,
twenty-year) integrated resource plan describing the strategies designed to meet current and future needs at the lowest cost to the utility and its ratepayers.
See Chapter 6 - Integrated Resource Portfolio for details on how we model
demand and supply coming together to provide the least cost/best risk portfolio of resources.
A short-term (e.g., two-year) plan outlining the
specific actions to be taken by the utility in implementing the integrated resource plan.
See Chapter 9 - Action Plan for actions to
be taken in implementing the IRP.
4 Relationship Between Plans. All plans following the initial integrated resource plan shall include a progress report that relates the new plan to the previously filed plan.
Avista strives to meet at least bi-annually with Staff and/or Commissioners to discuss the state of the market, procurement planning practices, and any other issues that may impact resource needs or other analysis within the IRP.
5 Plans to Be Considered in Rate Cases. The
integrated resource plan will be considered with other available information to evaluate the
performance of the utility in rate proceedings before the Commission.
We prepare and file our plan in part to
establish a public record of our plan.
6 Public Participation. In formulating its plan, the gas utility must provide an opportunity for public participation and comment and must provide methods that will be available to the public of validating predicted performance.
Avista held four Technical Advisory Committee meetings beginning in June and ending in November. See Chapter 1 - Introduction for more detail about public participation in the IRP process.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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7 Legal Effect of Plan. The plan constitutes the base line against which the utility's performance will ordinarily be measured. The requirement for implementation of a plan does not mean that the plan must be followed without deviation. The requirement of implementation of a plan means that
a gas utility, having made an integrated resource plan to provide adequate and reliable service to its
gas customers at the lowest system cost, may and should deviate from that plan when presented with responsible, reliable opportunities to further lower its planned system cost not anticipated or identified in existing or earlier plans and not undermining the utility's reliability.
See section titled "Avista's Procurement Plan" in Chapter 4 - Supply-Side Resources. Among other details we discuss plan revisions in response to changing market conditions.
8 In order to encourage prudent planning and prudent deviation from past planning when presented with opportunities for improving upon a plan, a gas
utility's plan must be on file with the Commission and available for public inspection. But the filing of
a plan does not constitute approval or disapproval of the plan having the force and effect of law, and deviation from the plan would not constitute violation of the Commission's Orders or rules. The prudence of a utility's plan and the utility's prudence in following or not following a plan are matters that
may be considered in a general rate proceeding or other proceedings in which those issues have been noticed.
See also section titled "Alternate Supply-Side Scenarios" in Chapter 6 - Integrated Resource Portfolio where we discuss
different supply portfolios that are responsive to changing assumptions about resource
alternatives.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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APPENDIX 1.2: OREGON PUBLIC UTILITY COMMISSION IRP STANDARD AND
GUIDELINES – ORDER 07- 002
Guideline 1: Substantive Requirements
1.a.1 All resources must be evaluated on a consistent and comparable basis. All resource options considered, including demand-side and supply-side are modeled in SENDOUT® utilizing the same common general assumptions, approach and methodology.
1.a.2 All known resources for meeting the
utility’s load should be considered, including supply-side options which focus on the generation, purchase and transmission of power – or gas purchases, transportation, and storage – and demand-side options which focus on conservation and demand response.
Avista considered a range of resources including demand-side management, distribution system enhancements, capacity release recalls, interstate pipeline transportation, interruptible customer supply, and storage options including liquefied natural gas. Chapter 3 and Appendix 3.1 documents Avista’s demand-side management resources considered. Chapter 4 and Appendix 6.3 documents supply-side resources. Chapter 6 and 7 documents how Avista developed and assessed each of these resources. 1.a.3 Utilities should compare different resource fuel types, technologies, lead times, in-service dates, durations and locations in portfolio risk modeling.
Avista considered various combinations of technologies, lead times, in-service dates, durations, and locations. Chapter 6 provides details about the modeling methodology and results. Chapter 4 describes resource attributes and Appendix 6.3
summarizes the resources’ lead times, in-service dates and locations.
1.a.4 Consistent assumptions and methods should be used for evaluation of all resources.
Appendix 6.2 documents general assumptions used in
Avista’s SENDOUT® modeling software. All portfolio resources both demand and supply-side were evaluated within SENDOUT® using the same sets of inputs.
1.a.5 The after-tax marginal weighted-average cost of capital (WACC) should be used to discount all future resource costs.
Avista applied its after-tax WACC of 4.36% to discount all future resource costs. (See general assumptions at Appendix 6.2)
1.b.1 Risk and uncertainty must be considered. Electric utilities only Not Applicable
1.b.2 Risk and uncertainty must be
considered. Natural gas utilities
should consider demand (peak,
swing and base-load), commodity
supply and price, transportation
availability and price, and costs to
comply with any regulation of
greenhouse gas (GHG) emissions.
Risk and uncertainty are key considerations in long
term planning. In order to address risk and
uncertainties a wide range of sensitivity, scenario and
portfolio analysis is completed. A description of risk
associated with each scenario is included in Appendix
2.6.

Avista performed 33 sensitivities on demand and price. From there five demand scenarios were developed (Table 1.1) for SENDOUT® modeling purposes. Monthly demand coefficients were developed for base, heating demand while peak demand was contemplated through modeling a weather planning standard using 99% probability (see heating degree day data in Appendix 2.4).
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Avista evaluated several price forecasts and
performed stochastic simulations to derive a high and
a low price based on the Expected price.

Avista stochastic modeling techniques for price and
weather variables to analyze weather sensitivity and
to quantify the risk to customers under varying price
environments. While there continues to be some
uncertainty around GHG emission, Avista considered
GHG emissions regulatory compliance costs in
Appendix 3.2. As currently modeled, we include a
carbon adder if the commodity is selected in the base Utilities should identify in their plans any additional sources of risk and uncertainty.
Avista evaluated additional risks and uncertainties. Risks associated with the planning environment are detailed in Chapter 0 Introduction. Avista also analyzed demand risk which is detailed in Chapter 2. Chapter 3 discusses the uncertainty around how much DSM is achievable. Supply-side resource risks are discussed in Chapter 4. Chapter 6 and 7 discusses the variables modeled for scenario and stochastic risk analysis.
1c The primary goal must be the
selection of a portfolio of resources
with the best combination of
expected costs and associated risks
and uncertainties for the utility and
its customers.
Avista evaluated cost/risk tradeoffs for each of the risk
analysis portfolios considered. See Chapter 5 and 6
plus supporting information in Appendix 2.6 for
Avista’s portfolio risk analysis and determination of the
preferred portfolio.
The planning horizon for analyzing
resource choices should be at least
20 years and account for end
effects. Utilities should consider all
costs with a reasonable likelihood of
being included in rates over the long
term, which extends beyond the
planning horizon and the life of the
resource.
Avista used a 20-year study period for portfolio
modeling. Avista contemplated possible costs beyond
the planning period that could affect rates including
end effects such as infrastructure decommission costs
and concluded there were no significant costs
reasonably likely to impact rates under different
resource selection scenarios.
Utilities should use present value of
revenue requirement (PVRR) as the
key cost metric. The plan should
include analysis of current and
estimated future costs of all long-
lived resources such as power
plants, gas storage facilities and
pipelines, as well as all short-lived
resources such as gas supply and short-term power purchases.
Avista’s SENDOUT® modeling software utilizes a
PVRR cost metric methodology applied to both long
and short-lived resources.
To address risk, the plan should
include at a minimum: 1) Two
measures of PVRR risk: one that
measures the variability of costs and
one that measures the severity of
bad outcomes. 2) Discussion of the
proposed use and impact on costs
and risks of physical and financial
hedging.
Avista, through its stochastic analysis, modeled 1,000
scenarios around varying gas price inputs via Monte
Carlo iterations developing a distribution of Total 20
year cost estimates utilizing SENDOUT®’s PVRR
methodology. Chapter 7 further describes this
analysis. The variability of costs is plotted against the
Expected Case while the scenarios beyond the 95th
percentile capture the severity of outcomes. Chapter 4
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discusses Avista’s physical and financial hedging methodology. The utility should explain in its plan how its resource choices appropriately balance cost and risk.
Chapter 4, 5, 6, and 7 describe various specific resource considerations and related risks, and describes what criteria we used to determine what resource combinations provide an appropriate balance between cost and risk.
1d The plan must be consistent with the long-run public interest as expressed in Oregon and federal energy policies.
Avista considered current and expected state and federal energy policies in portfolio modeling. Chapter 6 describes the decision process used to derive portfolios, which includes consideration of state resource policy directions.
Guideline 2: Procedural Requirements
2a The public, including other utilities, should be allowed significant
involvement in the preparation of the IRP. Involvement includes
opportunities to contribute
information and ideas, as well as to
receive information. Parties must
have an opportunity to make
relevant inquiries of the utility
formulating the plan.
Chapter 1 provides an overview of the public process and documents the details on public meetings held for
the 2018 IRP. Avista encourages participation in the development of the plan, as each party brings a
unique perspective and the ability to exchange
information and ideas makes for a more robust plan.
While confidential information must be protected, the utility should make public, in its plan, any non-confidential information that is relevant to its resource evaluation and action plan.
The entire IRP, as well as the TAC process, includes all of the non-confidential information the company used for portfolio evaluation and selection. Avista also provided stakeholders with non-confidential information to support public meeting discussions via email. The document and appendices will be available on the company website for viewing. The utility must provide a draft IRP for public review and comment prior
to filing a final plan with the
Commission.
Avista distributed a draft IRP document for external review to all TAC members on January 4, 2021 and
requested comments by February 3, 2021
Guideline 3: Plan Filing, Review and Updates
3a Utility must file an IRP within two
years of its previous IRP
acknowledgement order.
Acknowledgement of the 2018 IRP was on March 11,
2020. The 2021 IRP will be filed on April 1, 2021 or
within two years of previous acknowledgement order
3b Utility must present the results of its
filed plan to the Commission at a
public meeting prior to the deadline
for written public comment.
Avista will work with Staff to fulfill this guideline
following filing of the IRP.
3c Commission staff and parties should
complete their comments and
recommendations within six months
of IRP filing
Pending
3d The Commission will consider comments and recommendations on
a utility’s plan at a public meeting
before issuing an order on
acknowledgment. The Commission
may provide the utility an
opportunity to revise the plan before
issuing an acknowledgment order
Pending
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3e The Commission may provide direction to a utility regarding any additional analyses or actions that the utility should undertake in its next IRP.
Pending
3f Each utility must submit an annual update on its most recently acknowledged plan. The update is due on or before the acknowledgment order anniversary date. Once a utility anticipates a significant deviation from its acknowledged IRP, it must file an update with the Commission, unless the utility is within six months of
filing its next IRP. The utility must
summarize the update at a
Commission public meeting. The
utility may request acknowledgment
of changes in proposed actions
identified in an update
The annual update was submitted on January 26, 2020. The filing was a filing requesting an extension from August 31, 2020 to April 1, 2021. Approval was given through Order 20-071 on March 11, 2020.
3g Unless the utility requests acknowledgement of changes in proposed actions, the annual update is an informational filing that:
 Describes what actions the utility has taken to implement the plan;
 Provides an assessment of what has changed since the acknowledgment order that affects the action plan, including changes in such factors as load, expiration of resource contracts,
supply-side and demand-side resource acquisitions, resource
costs, and transmission availability; and
 Justifies any deviations from the acknowledged action plan.
The updates described in 3f above explained changes since acknowledgment of the 2018 IRP and an update of emerging planning issues. The updates did not request acknowledgement of any changes.
Guideline 4: Plan Components
At a minimum, the plan must include
the following
elements:

4a An explanation of how the utility met
each of the substantive and
procedural requirements.
This table summarizes guideline compliance by
providing an overview of how Avista met each of the
substantive and procedural requirements for a natural
gas IRP.
4b Analysis of high and low load growth
scenarios in addition to stochastic
load risk analysis with an
explanation of major assumptions.
Avista developed six demand growth forecasts for
scenario analysis. Stochastic variability of demand
was also captured in the risk analysis. Chapter 2
describes the demand forecast data and Chapter 7
provides the scenario and risk analysis results.
Appendix 5 details major assumptions.
4c For electric utilities only Not Applicable
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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4d A determination of the peaking,
swing and base-load gas supply and
associated transportation and
storage expected for each year of
the plan, given existing resources;
and identification of gas supplies
(peak, swing and base-load),
transportation and storage needed
to bridge the gap between expected
loads and resources.
Figures 6.10 – 6.17 summarize graphically projected
annual peak day demand and the existing and
selected resources by year to meet demand for the
expected case. Appendix 6.1 and 6.2 summarizes the
peak day demand for the other demand scenarios.
4e Identification and estimated costs of
all supply-side and demand-side
resource options, taking into
account anticipated advances in
technology
Chapter 3 and Appendix 3.1 identify the demand-side
potential included in this IRP. Chapter 4, 5 & 6 and
Appendix 6.3 identify the supply-side resources.
4f Analysis of measures the utility intends to take to provide reliable
service, including cost-risk tradeoffs.
Chapter 6 and 7 discuss the modeling tools, customer growth forecasting and cost-risk considerations used
to maintain and plan a reliable gas delivery system.
These Chapters also capture a summary of the
reliability analysis process demonstrated in the four
TAC meetings.
Chapter 4 discusses the diversified infrastructure and
multiple supply basin approach that acts to mitigate
certain reliability risks. Appendix 2.6 highlights key
risks associated with each portfolio.
4g Identification of key assumptions about the future (e.g. fuel prices and environmental compliance costs) and alternative scenarios considered.
Appendix 7 and Chapter 7 describe the key assumptions and alternative scenarios used in this IRP.
4h Construction of a representative set of resource portfolios to test various operating characteristics, resource
types, fuels and sources,
technologies, lead times, in-service
dates, durations and general
locations - system-wide or delivered
to a specific portion of the system.
This Plan documents the development and results for portfolios evaluated in this IRP (see Table 7.1 for scenarios considered).
4i Evaluation of the performance of the candidate portfolios over the range of identified risks and uncertainties.
We evaluated our candidate portfolio by performing stochastic analysis using SENDOUT® varying price under 1,000 different scenarios. Additionally, we test the portfolio of options with the use of SENDOUT® under deterministic scenarios where demand and price vary. For resources selected, we assess other risk factors such as varying lead times required and potential for cost overruns outside of the amounts included in the modeling assumptions. 4j Results of testing and rank ordering of the portfolios by cost and risk
metric, and interpretation of those
results.
Avista’s four distinct geographic Oregon service territories limit many resource option synergies which
inherently reduces available portfolio options.
Feasibility uncertainty, lead time variability and
uncertain cost escalation around certain resource
options also reduce reasonably viable options.
Chapter 4 describes resource options reviewed
including discussion on uncertainties in lead times and
costs as well as viability and resource availability (e.g.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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LNG). Appendix 6.3 summarizes the potential resource options identifying investment and variable costs, asset availability and lead time requirements while results of resources selected are identified in Table 6.5 as well as graphically presented in Figure 6.18 and 6.19 for the Expected Case and Appendix 7.1 for the High Growth case. 4k Analysis of the uncertainties associated with each portfolio evaluated
See the responses to 1.b above.
4l Selection of a portfolio that represents the best combination of cost and risk for the utility and its customers
Avista evaluated cost/risk tradeoffs for each of the risk analysis portfolios considered. Chapter 6 and Appendix 2.6 show the company’s portfolio risk analysis, as well as the process and determination of the preferred portfolio.
4m Identification and explanation of any inconsistencies of the selected portfolio with any state and federal energy policies that may affect a utility's plan and any barriers to implementation
This IRP is presumed to have no inconsistencies.
4n An action plan with resource activities the utility intends to undertake over the next two to four years to acquire the identified resources, regardless of whether the activity was acknowledged in a previous IRP, with the key attributes of each resource specified as in portfolio testing.
Chapter 9 presents the IRP Action Plan with focus on the following areas:
 Modeling
 Policy
 Supply/capacity/distribution
 Forecasting
 Regulatory communication
 DSM
Guideline 5: Transmission
5 Portfolio analysis should include
costs to the utility for the fuel
transportation and electric
transmission required for each
resource being considered. In
addition, utilities should consider
fuel transportation and electric
transmission facilities as resource
options, taking into account their
value for making additional
purchases and sales, accessing
less costly resources in remote
locations, acquiring alternative fuel
supplies, and improving reliability.
Not applicable to Avista’s gas utility operations.
Guideline 6: Conservation
6a Each utility should ensure that a
conservation potential study is
conducted periodically for its entire
service territory.
AEG performed a conservation potential assessment
study for our 2021 IRP. A discussion of the study is
included in Chapter 3. The full study document is in
Appendix 3.1. Avista incorporates a comprehensive
assessment of the potential for utility acquisition of
energy-efficiency resources into the regularly-
scheduled Integrated Resource Planning process.
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6b To the extent that a utility controls
the level of funding for conservation
programs in its service territory, the
utility should include in its action
plan all best cost/risk portfolio
conservation resources for meeting
projected resource needs,
specifying annual savings targets.
A discussion on the treatment of conservation
programs is included in Chapter 3 while selection
methodology is documented in Chapter 6. The action
plan details conservation targets, if any, as developed
through the operational business planning process.
These targets are updated annually, with the most
current avoided costs. Given the challenge of the low
cost environment, current operational planning and
program evaluation is still underway and targets for
Oregon have not yet been set.
6c To the extent that an outside party
administers conservation programs
in a utility's service territory at a
level of funding that is beyond the
utility's control, the utility should: 1)
determine the amount of
conservation resources in the best
cost/ risk portfolio without regard to
any limits on funding of conservation
programs; and 2) identify the
preferred portfolio and action plan
consistent with the outside party's
projection of conservation
acquisition.
Not applicable. See the response for 6.b above.
Guideline 7: Demand Response
7 Plans should evaluate demand response resources,
including voluntary rate programs, on par with other
options for meeting energy, capacity, and transmission
needs (for electric utilities) or gas supply and
transportation needs (for natural gas utilities).
Avista has periodically evaluated
conceptual approaches to
meeting capacity constraints
using demand-response and
similar voluntary programs.
Technology, customer
characteristics and cost issues
are hurdles for developing
effective programs.
Guideline 8: Environmental Costs
8 Utilities should include, in their base-case analyses, the
regulatory compliance costs they expect for CO2, NOx,
SO2, and Hg emissions. Utilities should analyze the
range of potential CO2 regulatory costs in Order No. 93-
695, from $0 - $40 (1990$). In addition, utilities should
perform sensitivity analysis on a range of reasonably
possible cost adders for NOx, SO2, and Hg, if applicable.
As discussed in Chapter 5, all
upstream emissions from the
point of use are included in this
IRP. The Environmental
Externalities discussion in
Appendix 3.2 describes our
analysis performed. See also the
guidelines addendum reflecting
revised guidance for
environmental costs per Order
08-339.

Guideline 9: Direct Access Loads
9 An electric utility's load-resource balance should exclude
customer loads that are effectively committed to service
by an alternative electricity supplier.
Not applicable to Avista’s gas
utility operations.
Guideline 10: Multi-state utilities
10 Multi-state utilities should plan their generation and transmission systems, or gas supply and delivery, on an The 2021 IRP conforms to the multi-state planning approach.
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integrated-system basis that achieves a best cost/risk portfolio for all their retail customers.
Guideline 11: Reliability
11 Electric utilities should analyze reliability within the risk modeling of the actual portfolios being considered. Loss of load probability, expected planning reserve margin, and expected and worst-case unserved energy should be determined by year for top-performing portfolios. Natural gas utilities should analyze, on an integrated basis, gas supply, transportation, and storage, along with demand-side resources, to reliably meet peak, swing, and base-load system requirements. Electric and natural
gas utility plans should demonstrate that the utility’s chosen portfolio achieves its stated reliability, cost and risk objectives.
Avista’s storage and transport resources while planned around meeting a peak day planning standard, also provides opportunities to capture off season pricing while providing system flexibility to meet swing and base-load requirements. Diversity in our transport options enables at least dual fuel source options in event of a transport disruption. For areas with only one fuel source option the cost of duplicative infrastructure is not
feasible relative to the risk of
generally high reliability
infrastructure.

Guideline 12: Distributed Generation
12 Electric utilities should evaluate distributed
generation technologies on par with other supply-side
resources and should consider, and quantify where
possible, the additional benefits of distributed generation.
Not applicable to Avista’s gas
utility operations.
Guideline 13: Resource Acquisition
13a An electric utility should: identify its proposed acquisition strategy for each resource in its action plan; Assess the advantages and disadvantages of owning a resource instead of purchasing power from another party; identify any Benchmark Resources it plans to consider in competitive bidding.
Not applicable to Avista’s gas utility operations.
13b Natural gas utilities should either describe in the IRP their bidding practices for gas supply and transportation, or provide a description of those practices following IRP acknowledgment.
A discussion of Avista’s procurement practices is detailed in Chapter 4.
Guideline 8: Environmental Costs
a. BASE CASE AND OTHER COMPLIANCE SCENARIOS:
The utility should construct a base-case scenario to
reflect what it considers to be the most likely regulatory
compliance future for carbon dioxide (CO2), nitrogen
oxides, sulfur oxides, and mercury emissions. The utility
also should develop several compliance scenarios
ranging from the present CO2 regulatory level to the
upper reaches of credible proposals by governing
entities. Each compliance scenario should include a time
profile of CO2 compliance requirements. The utility
should identify whether the basis of those requirements,
or “costs”, would be CO2 taxes, a ban on certain types of
resources, or CO2 caps (with or without flexibility
Upstream gas system
infrastructure (pipelines, storage
facilities, and gathering systems)
do produce CO2 emissions via
compressors used to pressurize
and move gas throughout the
system.

The Environmental Externalities
discussion in Appendix 3.2
describes our process for
addressing these costs.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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mechanisms such as allowance or credit trading or a
safety valve). The analysis should recognize significant
and important upstream emissions that would likely have
a significant impact on its resource decisions. Each
compliance scenario should maintain logical consistency,
to the extent practicable, between the CO2 regulatory
requirements and other key inputs.
b. TESTING ALTERNATIVE PORTFOLIOS AGAINST THE
COMPLIANCE SCENARIOS: The utility should
estimate, under each of the compliance scenarios, the
present value of revenue requirement (PVRR) costs and
risk measures, over at least 20 years, for a set of
reasonable alternative portfolios from which the preferred
portfolio is selected. The utility should incorporate end -effect considerations in the analyses to allow for comparisons of portfolios containing resources with economic or physical lives that extend beyond the planning period. The utility should also modify projected lifetimes as necessary to be consistent with the compliance scenario under analysis. In addition, the utility should include, if material, sensitivity analyses on a range of reasonably possible regulatory futures for nitrogen oxides, sulfur oxides, and mercury to further inform the preferred portfolio selection.
The Environmental Externalities
discussion in Appendix 3.2
describes our process for
addressing these costs.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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APPENDIX 2.1: ECONOMIC OUTLOOK AND CUSTOMER COUNT
FORECAST
I. Service Area Economic Performance and Outlook

Avista’s core service area for natural gas includes Eastern Washington, Northern Idaho,
and Southwest Oregon. Smaller service islands are also located in rural South-Central Washington and Northeast Oregon. Our service area is dominated by four
metropolitan statistical areas (MSAs): the Spokane-Spokane Valley, WA MSA
(Spokane-Stevens counties); the Coeur d’Alene, ID MSA (Kootenai County); the
Lewiston-Clarkson, ID-WA MSA (Nez Perce-Asotin counties); the Medford, OR MSA
(Jackson County); and Grants Pass, OR MSA (Josephine County). These five MSAs
represent the primary demand for Avista’s natural gas and account for 75% of both
customers (i.e., meters) and load. The remaining 25% of customers and load are
spread over low density rural areas in all three states.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 33 of 794
Figure 1: Employment and Population Recovery, December 2007- December 2020
Data source: Employment from the BLS; population from the U.S. Census.
In the wake of the Great Recession, our service area recovered more slowly than the U.S. Although the
U.S. recession officially ended in June 2009 (dated by the National Bureau of Economic Research), our
service area did not start a significant employment recovery until the second half of 2012 (Figure 1, top
and bottom graph). However, by the end of 2015, year-over-year employment growth exceeded U.S.
growth and employment levels returned to pre-recession levels. Due to strong employment growth in the
2016-2019 period, the total percentage gain in employment was roughly the same as the U.S. by the
middle of 2018. As a result, service area population growth, which is significantly influenced by in-
migration through employment opportunities, continued to improve after 2014 (Figure 2). This is important
because population growth is the largest contributor to overall customer growth.

However, as Figure 1 shows Avista’s service areas did not escape the employment impacts of COIVD-19
induced recession at the start of 2020. The expectation in IRP customer forecast is that COVID-19
recession will slow population growth in 2021, with a return to pre-pandemic growth starting in 2022.
Historically, service area population growth has slowed in one or more years following an employment
shock.
-16%
-14%
-12%
-10%
-8%
-6%
-4%
-2%
0%
2%
4%
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Non-Farm Employment Growth (Dashed Shaded Box = Recession Period)
Avista WA-ID-OR MSAs U.S.
75
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85
90
95
100
105
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Non-Farm Employment Level (Dashed Shaded Box = Recession Period)
Avista WA-ID-OR MSAs U.S.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 34 of 794
Figure 2: Avista MSA Annual Population Growth, 2005-2019

Figure 3 shows that compared to the 2018 IRP, actual average customer growth in WA-ID over the 2018-
2018 period is considerably higher than forecasted. This reflects (1) stronger than expected population
growth, especially in ID, and (2) Avista’s LEAP gas conversion program in WA (which expired in February
2019). In contrast, OR’s actual growth rate is equal to forecast over the same period. Figure 4 shows
since the 2018 IRP, customer growth has significantly exceeded population growth, which reflects
customer growth from existing homes converting to gas in addition to new construction installing gas.
Compared to the 2018 IRP, this IRP shows a system-wide downward revision of approximately 1,400 customers by 2040. This reflects the net impact of a 1,400-customer increase in WA-ID and 2,800 decrease in OR. The OR change reflects lower forecasted population growth in the Roseburg and Klamath service regions. Figure 5 and Table 1 show the change in the customer forecast by for the system and by class between the 2016 and 2018 IRPs.
1.6%1.6%1.6%
1.2%
0.9%
0.7%
0.5%
0.4%
0.7%
1.0%
1.2%
1.6%1.6%
1.5%1.5%
0.0%
0.2%
0.4%
0.6%
0.8%
1.0%
1.2%
1.4%
1.6%
1.8%
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 35 of 794
Figure 3: Comparison of 2018-IRP Customer Growth Forecasts to Actuals, 2018-2020

Data source: Company data.
1.9%
1.6%1.5%1.6%
2.6%
2.3%
2.0%
2.3%
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
3.0%
2018 2019 2020 2018-2020 Average
WA-ID Forecasted vs. Actual Customer Growth Rates
WA-ID 2018 IRP Forecast WA-ID Actual
1.3%
1.2%1.1%1.2%
1.3%1.3%
1.0%
1.2%
0.0%
0.2%
0.4%
0.6%
0.8%
1.0%
1.2%
1.4%
1.6%
2018 2019 2020 2018-2020 Average
OR Forecasted vs. Actual Customer Growth Rates
OR 2018 IRP Forecast OR Actual
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 36 of 794
Figure 4: Customer and Population Growth, 2005-2019
Data source: Company data.
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
3.0%
3.5%
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
OR Population Growth vs. Residential Customer Growth
OR Customer Growth OR Population Growth
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
3.0%
3.5%
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
WA-ID Population Growth vs. Residential Customer Growth
WA-ID Customer Growth WA-ID Population Growth
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 37 of 794
Table 1: Change in Forecast between the 2018 IRP and 2021 IRP in 2040
Area Residential Commercial Industrial Total Change
WA-ID +2,493 - 1,077 -22 +1,394
OR -2,440 -351 -2 -2,793
System 53 -1,428 -24 -1,400 Figure 5: Comparison IRP Forecasted Customer Growth in WA-ID and OR, 2021-2040
Data source: Company data.
In past IRPs, the modeling approach for the majority of commercial customers assumed that residential
customer growth (WA-ID schedule 101 and OR schedule 410 in Medford and Klamath Falls regions) is a
driver of commercial customer growth (WA-ID schedule 101 and OR schedule 420 in Medford and
Klamath Falls). The use of residential customers as a forecast driver for commercial customers reflects
the historically high correlation between residential and commercial customer growth rates. However,
because of the LEAP program, schedule 101 residential customers are no longer the primary driver in the
commercial forecast in WA. The LEAP program altered the historical relationship between residential and
commercial customers because the program was not offered to commercial customers. As a result,
population has replaced residential customers as the primary driver of commercial customer forecast.
This is also the case for ID, but for different reasons. In ID, the relationship between residential and
commercial customers is changing such that using population directly produces better model diagnostics.

The forecast for system-wide industrial customers is lower compared to the 2018 IRP. Approximately
90% of industrial customers are in WA-ID. Figure 6 (top graph) shows total system-wide firm industrial
customers since 2004. Following a sharp drop over the 2004-2006 period, firm industrial customers
started to decline starting in 2016. It should be noted that some of the decline between 2019 and 2020
reflects a reclassification of some WA-ID customers to firm commercial schedules. This reclassification
reflects customers that were incorrectly placed in firm industrial schedules in years past. Separating out
WA-ID and OR (middle graph), the number of firm customers in WA-ID continuously fell over the 2004-
2011 period; stabilized over the 2012-15; and then started to decline again. In contrast, OR customers
increased over the 2004-2011 period (bottom graph). However, after a period of stability during the 2011-
2014 period, customers declined modestly. Therefore, like the 2018 IRP, the current IRP forecast shows
a declining base.
300,000
320,000
340,000
360,000
380,000
400,000
420,000
440,000
460,000
2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040
WA-ID-OR-Base 2018 IRP WA-ID-OR-Base 2021 IRP
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 38 of 794
Figure 7: Industrial Customer Count, 2004-2020

Data source: Company data. II. IRP Forecast Process and Methodology The customer forecasts are generated from forecasting models that are either regression models with ARIMA error corrections or simple smoothing models. The ARIMA error correction models are estimated
190
200
210
220
230
240
250
260
270
280
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
WA-ID-OR Firm Industrial Customers
190
200
210
220
230
240
250
260
270
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
WA-ID Firm Industrial Customers
0
5
10
15
20
25
30
35
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
OR Firm Industrial Customers
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 39 of 794
using SAS/ETS software. The customer forecasts are used as input into Sendout® to generate the IRP
load forecasts.
Population growth is the key driver for the residential and commercial customer forecasts. Other variables
include (1) seasonal dummy variables and (2) outlier dummy variables that control for extreme customer counts associated with double billing, software conversions, and customer movements from one billing schedule to another. As noted above, the population growth forecast is the key driver behind the customer forecast for WA -ID residential schedules 101 and OR residential schedule 410. These two schedules represent the majority of customers and, therefore, drive overall residential customer growth. Because of their size and growth potential, a multi-step forecasting process has been developed for the Spokane-Spokane Valley, Coeur
d’Alene, and Medford+Grants Pass MSAs. The process for forecasting population growth starts with a medium-term forecast horizon (2021-2025). This medium-term forecast is typically used for the annual financial forecast. However, during IRP years, this medium-term forecast is augmented with third party forecasts that cover the next twenty years. Starting with Figure 8, the five-year population forecast is a multi-step process that begins with a GDP forecast that drives the regional employment forecast, which in turn, drives a five-year population forecast. Figure 8: Forecasting Population Growth, 2020-2025

The forecasting models for regional employment growth are:
[1] 𝐺𝐸𝑀𝑃𝑦,𝑆𝑃𝐾= 𝜗0 +𝜗1𝐺𝐺𝐷𝑃𝑦,𝑈𝑆+𝜗2 𝐺𝐺𝐷𝑃𝑦−1,𝑈𝑆+𝜗3𝐺𝐺𝐷𝑃𝑦−2,𝑈𝑆+ 𝜔𝑆𝐶𝐷𝐾𝐶,1998−2000=1+ 𝜔𝑆𝐶𝐷𝐻𝐵,2005−2007=1 +𝜖𝑡,𝑦
[2] 𝐺𝐸𝑀𝑃𝑦,𝐾𝑂𝑂𝑇= 𝛿0 +𝛿1𝐺𝐺𝐷𝑃𝑦,𝑈𝑆+𝛿2𝐺𝐺𝐷𝑃𝑦−1,𝑈𝑆+𝛿3𝐺𝐺𝐷𝑃𝑦−2,𝑈𝑆+ 𝜔𝑂𝐿𝐷1994=1+ 𝜔𝑂𝐿𝐷2009=1+ 𝜔𝑆𝐶𝐷𝐻𝐵,2005−2007=1+𝜖𝑡,𝑦
[3] 𝐺𝐸𝑀𝑃𝑦,𝐽𝐴𝐶𝐾+𝐽𝑂𝑆= 𝜙0 +𝜙1𝐺𝐺𝐷𝑃𝑦,𝑈𝑆+𝜙2𝐺𝐺𝐷𝑃𝑦−1,𝑈𝑆+𝜙3𝐺𝐺𝐷𝑃𝑦−2,𝑈𝑆+ 𝜔𝑆𝐶𝐷𝐻𝐵,2004−2005=1+𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (1,0,0)(0,0,0)12

SPK is Spokane, WA (Spokane MSA), KOOT is Kootenai, ID (Coeur d’Alene MSA), and JACK+JOS is for
the combination of Jackson County, OR (Medford MSA) and Josephine County, OR (Grants Pass MSA).
GEMPy is employment growth in year y, GGDPy,US is U.S. real GDP growth in year y. DKC is a dummy
variable for the collapse of Kaiser Aluminum in Spokane, and DHB, is a dummy for the housing bubble,
specific to each region. The average GDP forecasts are used in the estimated model to generate five-
year employment growth forecasts. The employment forecasts are then averaged with IHS’s forecasts for
the same counties so that:

[4] 𝐹𝐴𝑣𝑔(𝐺𝐸𝑀𝑃𝑦,𝑆𝑃𝐾)= 𝐹(𝐺𝐸𝑀𝑃𝑦,𝑆𝑃𝐾)+𝐹(𝐺𝐼𝐻𝑆𝐸𝑀𝑃)𝑦,𝑆𝑃𝐾)
2

[5] 𝐹𝐴𝑣𝑔(𝐺𝐸𝑀𝑃𝑦,𝐾𝑂𝑂𝑇)= 𝐹(𝐺𝐸𝑀𝑃𝑦,𝐾𝑂𝑂𝑇 )+𝐹(𝐺𝐼𝐻𝑆𝐸𝑀𝑃𝑦,𝐾𝑂𝑂𝑇)
2
Average GDP Growth
Forecasts:
•IMF, FOMC,
Bloomberg, etc.
•Average forecasts
out 5-yrs from
2020.
Non-farm Employment
Growth Model:
•Model links year y, y-1,
and y-2 GDP growth to
year y regional
employment growth.
•Forecast out 5-yrs from
2020.
•Averaged with GI
forecasts.

Regional Population Growth Models:
•Model links regional, U.S., and CA
year y-1 employment growth to year
y county population growth.
•Forecast out 5-yrs from 2020 for
Spokane, WA; Kootenai, ID; and
Jackson+Josephine, OR.
•Averaged with IHS forecasts in ID
and OR and OFM forecasts in WA.
•Growth rates used to generate
population forecasts for customer
forecasts for residential schedules 1,
101, and 410.
EMP GDP
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 40 of 794

[6] 𝐹𝐴𝑣𝑔(𝐺𝐸𝑀𝑃𝑦,𝐽𝐴𝐶𝐾+𝐽𝑂𝑆)= 𝐹(𝐺𝐸𝑀𝑃𝑦,𝐽𝐴𝐶𝐾+𝐽𝑂𝑆 )+𝐹(𝐺𝐼𝐻𝑆𝐸𝑀𝑃𝑦,𝐽𝐴𝐶𝐾+𝐽𝑂𝑆)
2

Averaging reduces the systematic errors of a single-source forecast. The averages [8.4] through [8.6] are
used to generate the population growth forecasts, which are described next.

The forecasting models for regional population growth are:

[7] 𝐺𝑃𝑂𝑃𝑦,𝑆𝑃𝐾= 𝜅0 +𝜅1𝐺𝐸𝑀𝑃𝑦−1,𝑆𝑃𝐾+𝜅2𝐺𝐸𝑀𝑃𝑦−2,𝑈𝑆+ 𝜔𝑂𝐿𝐷2001=1+𝜖𝑡,𝑦

[8] 𝐺𝑃𝑂𝑃𝑦,𝐾𝑂𝑂𝑇= 𝛼0 +𝛼1𝐺𝐸𝑀𝑃𝑦−1,𝐾𝑂𝑂𝑇+𝛼2𝐺𝐸𝑀𝑃𝑦−2,𝑈𝑆+ 𝜔𝑂𝐿𝐷1994=1 + 𝜔𝑂𝐿𝐷2002=1+ 𝜔𝑆𝐶𝐷𝐻𝐵,2007↑=1 +𝜖𝑡,𝑦
[9] 𝐺𝑃𝑂𝑃𝑦,𝐽𝐴𝐶𝐾+𝐽𝑂𝑆= 𝜓0 +𝜓1𝐺𝐸𝑀𝑃𝑦−1,𝐽𝐴𝐶𝐾+𝐽𝑜𝑠+𝜓2𝐺𝐸𝑀𝑃𝑦−2,𝐶𝐴+ 𝜔𝑂𝐿𝐷1991=1+ 𝜔𝑆𝐶𝐷𝐻𝐵,2004−2006=1+𝜖𝑡,𝑦
D2001=1 and D1991=1 are a dummy variables for recession impacts. GEMPy-1,US is U.S. employment growth in year y-1 and GEMPy-2, and CA is California Employment growth in year y-1. Because of its close proximity to CA, CA employment growth is better predictor of Jackson, OR employment growth than U.S. growth. The averages [8.4] through [8.6] are used in [7] through [9] to generate population growth
forecasts. These forecasts are combined with IHS’s forecasts for Kootenai, ID; Jackson, OR; Josephine, OR, and the Office for Financial Management (OFM) for Spokane, WA in the form of a simple average:
[10] 𝐹𝐴𝑣𝑔(𝐺𝑃𝑂𝑃𝑦,𝑆𝑃𝐾)= 𝐹(𝐺𝑃𝑂𝑃𝑦,𝑆𝑃𝐾)+𝐹(𝐺𝑂𝐹𝑀𝑃𝑂𝑃𝑦,𝑆𝑃𝐾)
2

[11] 𝐹𝐴𝑣𝑔(𝐺𝑃𝑂𝑃𝑦,𝐾𝑂𝑂𝑇)= 𝐹(𝐺𝑃𝑂𝑃𝑦,𝐾𝑂𝑂𝑇 )+𝐹(𝐺𝐼𝐻𝑆𝑃𝑂𝑃𝑦,𝐾𝑂𝑂𝑇)
2

[12] 𝐹𝐴𝑣𝑔(𝐺𝑃𝑂𝑃𝑦,𝐽𝐴𝐶𝐾+𝐽𝑂𝑆)= 𝐹(𝐺𝑃𝑂𝑃𝑦,𝐽𝐴𝐶𝐾+𝐽𝑂𝑆 )+𝐹(𝐺𝐼𝐻𝑆𝑃𝑂𝑃𝑦,𝐽𝐴𝐶𝐾+𝐽𝑂𝑆)
2
Here, FAvg(GPOPy) is used to forecast population to forecast residential customers in WA-ID 101 and OR 410 schedules for the Spokane, Kootenai, and Jackson+Josephine areas. In the case of Spokane, OFM
forecasts are used because the IHS’s forecasts exhibit a level and time-path that is inconsistent with recent population behavior. The population growth forecasts for the Douglas (Roseburg), Klamath (Klamath Falls); and Union (La Grande) counties come directly from IHS. Since all forecasted growth rates are annualized, they are converted to monthly rates. By way of example, the following is regression model for residential 101 customers for the Spokane region:
𝐶𝑡,𝑦,𝑊𝐴101.𝑟=𝛼0 +𝜏𝑃𝑂𝑃𝑡,𝑦,𝑆𝑃𝐾+𝝎𝑺𝑫𝑫𝒕,𝒚+𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2015=1 +𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2016=1+𝜔𝑂𝐿𝐷𝑀𝑎𝑟 2018=1
+𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2018=1+𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (12,1,0)(0,0,0)12
Where: tPOPt,y,SPK = t is the coefficient to be estimated and POPt,y,SPK is the interpolated population level in month t, in year y, for Spokane. The monthly interpolation of historical data assumes that between years, population accumulates following the standard population growth model: POPy,SPK = POPy-
1,SPKer.
wSDDt,y = wSD is a vector of seasonal dummy (SD) coefficients to be estimated and Dt,y is a vector monthly seasonal dummies to account of customer seasonality. Dt,y = 1 for the relevant month. wOLDOct 2015=1 = wOL outlier (OL) coefficient to be estimated and D is a dummy that equals 1 for October 2015. There are three additional outlier dummies that follow August 2010. In some cases, the dummy variable may be a structural change (SC) dummy that takes the form, for example, wSCDOct 2015↑=1; in this case, the dummy takes the value of 1 for October 2015 forward.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 41 of 794
ARIMAet,y(12,1,0)(0,0,0)12 = is the error correction applied to the model’s initial error structure. This term follows the following from ARIMAet,y (p,d,q)(pk,dk,qk)k. The term p is the autoregressive (AR) order, d is the differencing order, and q is the moving average (MA) order. The term p k is the order of seasonal AR terms, dk is the order of seasonal differencing, and qk is the seasonal order of MA
terms. The seasonal values are related to “k,” which is the frequency of the data. With the current data set, k = 12. The customer forecast is generated by inputting forecasted values of POPt,y,SPK into the model estimated with historical data. All customer forecast equations are shown in the last section of this appendix. The above describes the medium-term population forecast to 2025. For IRPs, the medium-term customer forecasts must be extended an additional 15+ years. This is done using the IHS population forecast for Kootenai, Jackson+Josephine, Douglas, Klamath, and Union counties. That is, IHS is the sole source for forecasted population growth beyond the medium-term forecast horizon by [10] through [12]. In the case
of Spokane County, the forecast from Washington’s Office of Financial Management (OFM) is instead of
IHS’s. The choice to use OFM’s forecasts reflects the unusually sharp changes that have occurred in the
IHS forecasts for the Spokane MSA over a short period of time. Figure 9 shows how much these
forecasts have changed in level and shape since June 2012. From the October 2015 to March 2018
forecasts, there were significant changes for the 2015-2025 period. There is no clear rational for why
IHS’s forecasts changed so significantly between 2012 and 2018. For firm schedules without explicit
regression drivers like population, the forecast model run to cover the entire forecast period of the IRP.
Figure 9: Spokane MSA Forecast Comparison
Data source: IHS, Washington State of Office of Financial Management, and U.S. Census.
0.0%
0.2%
0.4%
0.6%
0.8%
1.0%
1.2%
1.4%
1.6%
1.8%
2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035
IHS June 2012 Forecast IHS October 2015 Forecast IHS March 2016 Forecast Actual
OFM 2017 IHS March 2017 Forecast IHS March 2018 Forecast
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 42 of 794
Figure 10: Annual Customer Growth for the Three Rate Classes, 2005-2020

Data source: Company data.
Figure 10 demonstrates that residential and commercial growth rates are highly correlated over the long-
run. Over the period shown, residential and commercial averaged about 1.6% and 1.1%, respectively.
Residential growth is, on average, higher than population growth because of existing households
converting to natural gas at the same time new construction is installing gas. However, by 2009, with the
Great Recession and increased natural gas saturation, the different between customer growth and
population growth almost disappears. As the economy improved in the 2015-2019 period, residential and
commercial growth accelerated due to an improved economy and gas conversion incentives in
Washington in the 2016-2019 period.

In contrast, the behavior of Industrial customer growth looks quite different. Customer growth is both
lower and more volatile. The average growth rate since 2005 is -1.4%, reflecting a trend of nearly flat or
slowly declining customers, depending on the jurisdiction. In addition, the standard deviation of year-
over-year growth is 2% compared to 0.8% for residential and 0.6% for commercial growth. The current
IRP forecast reflects this historical trend of weak growth.

Establishing High-Low Cases for IRP Customer Forecast

The customer forecasts for this IRP include high and low cases that set the expected bounds around the
base-case. Table 2 shows the base, low, and high customer forecasts along with the underlying
population growth assumption. The underlying population forecast is the primary driver for each of the
three cases.

-7%
-6%
-5%
-4%
-3%
-2%
-1%
0%
1%
2%
3%
4%
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
Residential Commercial Industrial
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 43 of 794
Table 2: Alternative Growth Cases, 2021-2045
Area Low Growth Base Growth High Growth
WA-ID:
WA-ID Customers 0.7% 1.1% 1.5%
WA Population 0.4% 0.7% 1.0% ID Population 0.8% 1.4% 2.0%
OR:
OR Customers 0.5% 0.7% 0.9%
OR Population 0.3% 0.5% 0.7%

System:
System Customers 0.6% 1.0% 1.3% System Population 0.4% 0.8% 1.1%
III. IRP Customer Forecast Equations 1. WA residential customer forecast models: [1] 𝐶𝑡,𝑦,𝑊𝐴101.𝑟=𝛼0 +𝜏𝑃𝑂𝑃𝑡,𝑦,𝑆𝑃𝐾+𝝎𝑺𝑫𝑫𝒕,𝒚+𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2015=1+𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2016=1 +𝜔𝑂𝐿𝐷𝑀𝑎𝑟 2018=1+
𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2018=1 +𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (12,1,0)(0,0,0)12

[1] Model notes:
1. WA schedule 2 customers are schedule 1 customers that have been moved to a new low-income schedule. The schedule started
in October 2015, so there is insufficient data for a more complicated model. In the first years of the program, the number o f
customers in this schedule started slowly declining under the original cap of 300 customers. However, this schedule has had its cap
removed and the number of customers has started to increase. In the spring 2020 forecast the average Δ = 6.6.

[2] 𝐶𝑡,𝑦,𝑊𝐴102.𝑟= 𝐶𝑡−1 +∆̅,𝑤ℎ𝑒𝑟𝑒 ∆̅ = ∑(𝐶𝑡,𝑦−𝐶𝑡−1,𝑦)
𝑁𝑓𝑜𝑟 𝑁 𝑚𝑜𝑛𝑡ℎ𝑠 𝑏𝑒𝑡𝑤𝑒𝑒𝑛 𝑂𝑐𝑡𝑜𝑏𝑒𝑟 2015 −𝑀𝑎𝑦 2020

[2] Model notes:
1. WA schedule 102 customers are schedule 101 customers that have been moved to a new low-income schedule. The schedule
started in October 2015, so there is insufficient data for a more complicated model. In the first years of the program, the number of
customers in this schedule started slowly declining under the original cap of 300 customers. However, this schedule has had its cap
removed and the number of customers has started to increase. In the spring 2020 forecast the average Δ = 3.4.
[3] 𝐶𝑡,𝑦,𝑊𝐴111.𝑟=𝛼0 + 𝜔𝑆𝐶𝐷𝑂𝑐𝑡 2011↑=1 + 𝜔𝑆𝐶𝐷𝑂𝑐𝑡 2013↑=1 +𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (8,1,0)(0,0,0)12

[3] Model notes:
1. Error structure white noise, but not quite normally distributed.
2. SC dummies control for a step-up in customers starting in October 2011 and October 2013. 2. ID residential customer forecast models: [4] 𝐶𝑡,𝑦,𝐼𝐷101.𝑟=𝛽0 +𝜏𝑃𝑂𝑃𝑡,𝑦,𝐾𝑂𝑂𝑇+𝝎𝑺𝑫𝑫𝒕,𝒚+𝜔𝑆𝐶𝐷𝐽𝑎𝑛 2007↑=1 +𝛾𝑅𝐴𝑀𝑃𝑇𝐽𝑎𝑛 2007 + 𝜔𝑂𝐿𝐷𝑀𝑎𝑦 2005=1 + 𝜔𝑂𝐿𝐷𝐽𝑢𝑙 2005=1 +
𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2005=1+ 𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2005=1+𝜔𝑂𝐿𝐷𝐽𝑢𝑛 2006=1 + 𝜔𝑂𝐿𝐷𝐽𝑎𝑛 2006=1 + 𝜔𝑂𝐿𝐷𝐽𝑢𝑛 2007=1+ 𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2007=1 +
𝜔𝑂𝐿𝐷𝐴𝑢𝑔 2011=1 + 𝜔𝑂𝐿𝐷𝑆𝑒𝑝𝑡 2011=1+ 𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2018=1 +𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (9,1,0)(0,0,0)12

[4] Model notes:
1. SC dummy and ramping time trend control for a change in the time-path of customer growth staring in January 2007.
2. The large number of OL dummies controls for a range of factors including changes in billing cycles, billing errors, and software
changes.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 44 of 794
[5] 𝐶𝑡,𝑦,𝐼𝐷111.𝑟=1
12 ∑𝐶𝑡−𝑗12𝑗=1
[5] Model notes:
1. Model changed to a 12-month moving average in fall 2020. There has been no customer growth since 2012.

3. WA commercial customer forecast models:

[6] 𝐶𝑡,𝑦,𝑊𝐴101.𝑐= 𝛼0 + 𝛼1𝑃𝑂𝑃𝑡,𝑦,𝑆𝑃𝐾+ 𝝎𝑺𝑫𝑫𝒕,𝒚+𝛾𝑅𝐴𝑀𝑃𝑇𝐽𝑎𝑛 2010 +𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2005=1+𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2007=1+𝜔𝑂𝐿𝐷𝑆𝑒𝑝 2013=1+
+𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2013=1+𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2015=1 +𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2016=1 +𝜔𝑂𝐿𝐷𝐽𝑢𝑛 2017=1 +𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2019=1 +𝜓𝐶𝑂𝑉𝐼𝐷𝐷𝐴𝑝𝑟−𝐽𝑢𝑙 2020=1+
𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (2,1,0)(0,0,0)12
[6] Model notes: 1. In the June 2017 forecast, Ct,y,WA101.r (residential customers from residential schedule 101) was replaced with POP for Spokane.
This was done to account for a new hookup tariff for residential gas customers in WA’s LEAP program. This tariff is more gen erous than the previous long-standing tariff. In addition, any savings in the hookup process could be passed on to the customer for equipment purchases or replacement. Since this tariff change excluded commercial and industrial customers, this significant ly accelerated residential hookups but not commercial hookups. As a result, this historical relationship between residential and
commercial customer growth has been altered. See also Tables 5.1 and 5.2. 2. RAMP variable was added in June 2019 because of increasing evidence that the sensitivity of commercial customer growth to population growth fell after 2009.
3. COVIDD dummy controls for the impact of the shut-down shock.
[7] 𝐶𝑡,𝑦,𝑊𝐴111.𝑐= 𝛼0 + 𝝎𝑺𝑫𝑫𝒕,𝒚+𝛾𝑅𝐴𝑀𝑃𝑇𝐴𝑝𝑟 2016 +𝛾𝑅𝐴𝑀𝑃𝑇𝑀𝑎𝑟 2018 +𝜔𝑆𝐶𝐷𝑁𝑜𝑣 2011↑=1 +𝜔𝑆𝐶𝐷𝐴𝑝𝑟 2016↑=1+𝜔𝑂𝐿𝐷𝐽𝑎𝑛 2007=1 +
𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2013=1 +𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2013=1+𝜔𝑂𝐿𝐷𝐽𝑢𝑛 2017=1 +𝜔𝑂𝐿𝐷𝑀𝑎𝑟 2018=1+𝜔𝑂𝐿𝐷𝑆𝑒𝑝 2018=1 +𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2018=1+𝜔𝑂𝐿𝐷𝑆𝑒𝑝 2019=1 +
𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2019=1 +𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (1,1,0)(0,0,0)12

[7] Model notes: 1. SC dummies and RAMP variables control for a complex set of steps and slope changes in the customer count. 4. ID commercial customer forecast models: [8] 𝐶𝑡,𝑦,𝐼𝐷101.𝑐= 𝛽0 + 𝛽1𝑃𝑂𝑃𝑡,𝑦,𝐾𝑜𝑜𝑡+𝜔𝑆𝐶𝐷𝑁𝑜𝑣 2005↑=1+𝜔𝑆𝐶𝐷𝑆𝑒𝑝 2006↑=1+𝜔𝑆𝐶𝐷𝑁𝑜𝑣 2007↑=1+𝜔𝑂𝐿𝐷𝑀𝑎𝑟 2005=1+
𝜔𝑂𝐿𝐷𝐽𝑢𝑛 2005=1 +𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2005=1 +𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2005=1+𝜔𝑂𝐿𝐷𝑀𝑎𝑟 2007=1+𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2015=1 +𝜔𝑂𝐿𝐷𝑆𝑒𝑝 2018=1+
𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2018=1 +𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (9,1,0)(3,1,0)12
[8] Model notes: 1. In the spring 2020 forecast, Ct,y,ID101.r (residential customers from residential schedule 101) was replaced with POP for Kootenai.
This was done because POP produced a model with improved diagnostic tests. Previously, Ct,y,ID101.r was being used as a forecast driver because of the historical positive correlation between residential and commercial customer growth. See Tables 5.1 an d 5.2.
2. SC dummies control for a step-up in customers in November 2005, September 2006, and November 2007.
[9] 𝐶𝑡,𝑦,𝐼𝐷111.𝑐= 𝛽0 +𝛾𝑅𝐴𝑀𝑃𝑇𝐽𝑎𝑛 2012 +𝜔𝑆𝐶𝐷𝑁𝑜𝑣 2008↑=1+𝜔𝑆𝐶𝐷𝑁𝑜𝑣 2011↑=1+𝜔𝑆𝐶𝐷𝐽𝑎𝑛 2012↑=1 +𝜔𝑂𝐿𝐷𝑆𝑒𝑝 2009=1 +
𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2011=1 +𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2015=1+𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2015=1 +𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (1,1,0)(0,0,0)12
[9] Model notes:
1. SC dummies control for a large step-up in customers starting in November 2008 and November 2011.
2. Ramping time trend and SC dummy starting in Jan 2012 control for a slowdown in customer growth. 5. WA industrial customer forecasts models: [10] 𝐶𝑡,𝑦,𝑊𝐴101.𝑖= 𝛼0 + 𝜔𝑆𝐶𝐷𝐴𝑝𝑟 2008↑=1+ 𝜔𝑆𝐶𝐷𝑂𝑐𝑡 2013↑=1 +𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2006=1+𝜔𝑂𝐿𝐷𝐽𝑎𝑛 2007=1+ 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2007=1 +
+ 𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2013=1+ 𝜔𝑂𝐿𝐷𝐽𝑎𝑛 2015=1+ 𝜔𝑂𝐿𝐷𝑀𝑎𝑟 2017=1+𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (7,1,0)(0,0,0)12

[10] Model notes:
1. SC dummies control for a step-down in customers starting in April 2008 and October 2013. [11] 𝐶𝑡,𝑦,𝑊𝐴111.𝑖= 𝐴𝑅𝐼𝑀𝐴(2,1,0)(0,0,0)12
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 45 of 794
[11] Model notes:
1. Error structure is white noise, but not quite normally distributed.
2. In January 2019, all three customers in schedule 121 industrial were moved to schedule 111, in addition to Boise Cascade Arden,
WA (under the company name Columbia Cedar) from schedule 25. This change of four customers falls within the normal variation
of customers in schedule 111; therefore, no explicit adjustment is made to the model [7.40] to account for this shift.
6. ID industrial customer forecast models:

[12] 𝐶𝑡,𝑦,𝐼𝐷101.𝑖=𝛽0 + 𝜔𝑆𝐶𝐷𝐷𝑒𝑐 2010↑=1+ 𝜔𝑆𝐶𝐷𝑁𝑜𝑣 2011↑=1+ 𝜔𝑆𝐶𝐷𝐷𝑒𝑐 2011↑=1+ 𝜔𝑆𝐶𝐷𝐽𝑢𝑛 2014↑=1+ 𝜔𝑆𝐶𝐷𝐽𝑎𝑛 2018↑=1 +
+ 𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2008=1+ 𝜔𝑂𝐿𝐷𝐽𝑢𝑙 2014=1+ 𝜔𝑂𝐿𝐷𝐽𝑎𝑛 2015=1+ 𝜔𝑂𝐿𝐷𝐽𝑎𝑛 2016=1+ 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2017=1 +𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (13,1,0)(0,0,0)12

[12] Model notes:
1. SC dummies control for step-downs in customers starting in December 2010, November 2011, December 2011, and January
2018; June 2014 controls for a step-up in customers.
2. The large number of OL dummies controls for a range of factors including changes in billing cycles, billing errors, and software
changes.
[13] 𝐶𝑡,𝑦,𝐼𝐷111.𝑖= 1
12 ∑𝐶𝑡−𝑗12𝑗=1

[13] Model notes:
1. Period of restriction reflects the restriction on the UPC model for this schedule.
2. Customer count stabilized in 2012; customer count fluctuates between 31 and 34 without any clear trend or seasonality.
[14] 𝐶𝑡,𝑦,𝐼𝐷112.𝑖= 1
12 ∑𝐶𝑡−𝑗12𝑗=1

[14] Model notes:
1. Customer count tends to increase in steps following prolonged periods of stability. No clear seasonality present.
7. Medford, OR forecasting models:

The forecasting models for the Medford region (Jackson County) are given below for the residential,
commercial, and industrial sectors:
Residential Sector, Customers:

[15] 𝐶𝑡,𝑦,𝑀𝐸𝐷410.𝑟= 𝛼0 +𝛼1𝑃𝑂𝑃𝑡,𝑦,𝐽𝐴𝐶𝐾+𝐽𝑂𝑆+𝝎𝑺𝑫𝑫𝒕,𝒚+𝛾𝑅𝐴𝑀𝑃𝑇𝐽𝑎𝑛 2008 +𝜔𝑆𝐶𝐷𝐽𝑎𝑛 2008↑ =1 + 𝜔𝑆𝐶𝐷𝑁𝑜𝑣 2004↑ =1 +
𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2005 =1 +𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (7,1,0)(0,0,0)12

[15] Model notes:
1. SC dummy and ramping time trend control for a change in the time-path of customer growth staring in January 2008.
2. POP is Jackson plus Josephine counties.
Commercial Sector, Customers:

[16] 𝐶𝑡,𝑦,𝑀𝐸𝐷420.𝑐= 𝛼0 +𝛼1𝐶𝑡,𝑦,𝑀𝐸𝐷410.𝑟 + 𝝎𝑺𝑫𝑫𝒕,𝒚+ 𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2009 =1 + 𝜔𝑂𝐿𝐷𝐽𝑎𝑛 2016 =1 +𝜓𝐶𝑂𝑉𝐼𝐷𝐷𝐴𝑝𝑟−𝐽𝑢𝑙 2020=1+
𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (7,1,0)(0,0,0)12

[16] Model notes: 1. Ct,y,MED410.r are residential customers from residential schedule 410. They are being used as a forecast driver because of the historical positive correlation between residential and commercial customer growth. See Tables 5.1 and 5.2. However, in the
future, POP may become a better driver. Model results with POP are fairly close to model shown above. 2. COVIDD dummy controls for the impact of the shut-down shock. [17] 𝐶𝑦,𝑀𝐸𝐷424.𝑐= 𝐶𝑦−1 +(𝛼0̂+𝛼1̂∆𝐸𝑀𝑃𝑦−1,4𝐶𝑜𝑢𝑛𝑡𝑦)

[17] Model notes:
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 46 of 794
1. This model reflects a recommendation by Oregon staff in the 2016 rate case to include employment as an economic driver for
schedule 424 commercial customers. The estimated equation in parenthesis reflects the regression estimated of ∆𝐶𝑦,𝑀𝐸𝐷424.𝑐=
𝛼0 +𝛼1∆𝐸𝑀𝑃𝑦−1,4𝐶𝑜𝑢𝑛𝑡𝑦+𝜀𝑡 using annual customer data since 2004. Annual data is used to smooth over the sometimes volatile
changes in the monthly customer number. In addition, customer increases and decreases around the long-run trend tend to occur
in steps. The combination of steps and month-to-month volatility creates significant economic problems when trying to model
around the monthly data. For example, even with intervention variables, tests for error normality always indicated non -normal error
terms with the use of monthly data.
2. ∆𝐶𝑦,𝑀𝐸𝐷424.𝑐 is the change in customers in year y (customer change between year y and y-1) and ∆𝐸𝑀𝑃𝑦−1,4𝐶𝑜𝑢𝑛𝑡𝑦 is the change
in total non-farm employment in Jackson, Josephine, Klamath, and Douglas counties in year y-1 (employment change between year
y-1 and y-2). Staff originally suggested lagged total employment for Oregon, but the correlation between schedule 424 customers
and employment for the three-county area is higher. The forecasted employment values for Jackson+Josephine County are derived
from the employment growth forecasts used in the Jackson+Josephine County population forecast. The forecasts for Douglas and
Klamath counties come from IHS. In IRP years, IHS forecasts all counties will be used for the out years.
3. The annual forecast value for each year, F(∙), is assumed to hold for each month of that year. That is: 𝐹(𝐶𝑦,𝑀𝐸𝐷424.𝑐)=
𝐹(𝐶𝑡,𝑦,𝑀𝐸𝐷424.𝑐). Given the step-like behavior of the monthly series, this is a reasonable assumption.
4. The forecast and regressions for this schedule can be found in the Excel file folder “OR 4County Sch 424c Cus.” [18] 𝐶𝑡,𝑦,𝑀𝐸𝐷444.𝑐= 1 𝑖𝑓 (𝑇𝐻𝑀/𝐶𝑡,𝑦)𝑀𝐸𝐷,444.𝑐>0

[19] Model notes:
1. There is typically only one customer served by this schedule. Therefore, the customer forecast is automatically set to on e
whenever the load forecast is greater than zero. In IRP years, the forecast is repeated out monthly until December 2045.
Industrial Sector, Customers:
[19] 𝐶𝑡,𝑦,𝑀𝐸𝐷420.𝑖= 1
12∑𝐶𝑡−𝑗12𝑗=1

[19] Model notes:
1. Data starts November 2006. Excluding outliers in November 2006, November 2009, and February 2011, the customer count
fluctuates between 9 and 16 without any clear trend or seasonality. Changes in the customer count occur in steps between
prolonged periods of stability.

[20] 𝐶𝑡,𝑦,𝑀𝐸𝐷424.𝑖=1
12 ∑𝐶𝑡−𝑗12𝑗=1

[20] Model notes:
1. Data starts January 2009. Excluding a January 2009 outlier, the customer count fluctuates between 1 and 3 without any clear
trend or seasonality. Customer count is most frequently reported as 2; however, starting in March 2018, the customer count fell to
one.
8. Roseburg, OR forecasting models: The forecasting models for the Roseburg region (Douglas County) are given below for the residential, commercial, and industrial sectors: Residential Sector, Customers: [21] 𝐶𝑡,𝑦,𝑅𝑂𝑆410.𝑟= 𝜑0+𝜑1𝑃𝑂𝑃𝑡,𝑦,𝐷𝑂𝑈𝐺𝐿𝐴𝑆+𝝎𝑺𝑫𝑫𝒕,𝒚+ 𝜔𝑆𝐶𝐷𝐽𝑎𝑛 2005↑ =1 +𝜔𝑆𝐶𝐷𝐷𝑒𝑐 2005↑ =1 +𝜔𝑆𝐶𝐷𝑁𝑜𝑣 2006↑ =1 +
𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2004 =1 +𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2004 =1+𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2007 =1 +𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2008 =1+ 𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2009 =1 +𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2018 =1 +
𝜔𝑂𝐿𝐷𝑀𝑎𝑟 2019 =1 +𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (12,1,0)(0,0,0)12

[21] Model notes:
1. POP is population for Douglas County, OR.
2. SC dummies control for large step-ups in customers in 2005 and 2006.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 47 of 794
Commercial Sector, Customers: [22] 𝐶𝑡,𝑦,𝑅𝑂𝑆420.𝑐= 𝜑0 +𝜑1𝑃𝑂𝑃𝑡,𝑦,𝐷𝑂𝑈𝐺𝐿𝐴𝑆+𝝎𝑺𝑫𝑫𝒕,𝒚+ 𝜔𝑆𝐶𝐷𝐷𝑒𝑐 2004↑ =1 +𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2004 =1 +𝜔𝑂𝐿𝐷𝐽𝑎𝑛 2005 =1 +
𝜔𝑂𝐿𝐷𝐽𝑎𝑛 2008 =1 + 𝜔𝑂𝐿𝐷𝑀𝑎𝑦 2016=1 + 𝜔𝑂𝐿𝐷𝑀𝑎𝑟 2019=1 +𝜔𝑂𝐿𝐷𝑆𝑒𝑝𝑡 2019 =1 + 𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2019=1 +𝜓𝐶𝑂𝑉𝐼𝐷𝐷𝐴𝑝𝑟−𝐽𝑢𝑙 2020=1+
𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (9,1,0)(0,0,0)12

[22] Model notes:
1. Model does not use schedule 410 customers as driver. This reflects the lack of correlation between residential 410 and
commercial 420 customer growth. However, POP was added for the 2018 gas IRP and it is significant at the 10% level
2. The lack of correlation noted in Point 1 could reflect Roseburg’s position between larger cities that offer a range of commercial
activities. Competition from these cities may be inhibiting commercial growth in Roseburg.
3. SC dummy controls for a significant step-up in customers starting in December 2004.
4. COVIDD dummy controls for the impact of the shut-down shock.

[23] 𝐶𝑡,𝑦,𝑅𝑂𝑆424.𝑐= 𝐶𝑦−1 +(𝜑0̂+𝜑1̂∆𝐸𝑀𝑃𝑦−1,4𝐶𝑜𝑢𝑛𝑡𝑦)

[23] Model notes:
1. This model reflects a recommendation by Oregon staff in the 2016 rate case to include employment as an economic driver for
schedule 424 commercial customers. The estimated equation in parenthesis reflects the regression estimated of ∆𝐶𝑦,𝑅𝑂𝑆424.𝑐=
𝛼0 +𝛼1∆𝐸𝑀𝑃𝑦−1,4𝐶𝑜𝑢𝑛𝑡𝑦+𝜀𝑡 using annual customer data since 2004. Annual data is used to smooth over the sometimes volatile
changes in the monthly customer number. In addition, customer increases and decreases around the long-run trend tend to occur
in steps. The combination of steps and month-to-month volatility creates significant economic problems when trying to model
around the monthly data. For example, even with intervention variables, tests for error normality always indicated non-normal error
terms with the use of monthly data.
2. ∆𝐶𝑦,𝑅𝑂𝑆424.𝑐 is the change in customers in year y (customer change between year y and y-1) and ∆𝐸𝑀𝑃𝑦−1,4𝐶𝑜𝑢𝑛𝑡𝑦 is the change in
total non-farm employment in Jackson, Josephine, Klamath, and Douglas counties in year y-1 (employment change between year y-
1 and y-2). Staff originally suggested lagged total employment for Oregon, but the correlation between schedule 424 customers and
employment for the three-county area is higher. The forecasted employment values for Jackson+Josephine County are derived
from the employment growth forecasts used in the Jackson+Josephine County population forecast. The forecasts for Douglas an d
Klamath counties come from IHS. In IRP years, IHS forecasts for all counties will be used for the out years.
3. The annual forecast value for each year, F(∙), is assumed to hold for each month of that year. That is: 𝐹(𝐶𝑦,𝑅𝑂𝑆424.𝑐)=
𝐹(𝐶𝑡,𝑦,𝑅𝑂𝑆424.𝑐). Given the step-like behavior of the monthly series, this is a reasonable assumption.
4. The forecast and regressions for this schedule can be found in the Excel file file folder “OR 4County Sch 424c Cus.” Industrial Sector, Customers:

[24] 𝐶𝑡,𝑦,𝑅𝑂𝑆420.𝑖= 1
12∑𝐶𝑡−𝑗12𝑗=1

[24] Model notes:
1. Data starts September 2009. Excluding a February 2015 outlier, the customer count fluctuates between 1 and 2 without any clear
trend or seasonality.
2. Due to the Compass software conversion, February 2015 is excluded from the historical data. The conversion resulted in a
double counting of customers in February 2015. Therefore, including this month leads to a significant over-forecast of customers.
9. Klamath Falls, OR forecasting models: The forecasting models for the Klamath Falls region (Klamath County) are given below for the residential, commercial, and industrial sectors: Residential Sector, Customers:

[25] 𝐶𝑡,𝑦,𝐾𝐿𝑀410.𝑟= 𝛽0 +𝛽1𝑃𝑂𝑃𝑡,𝑦,𝐾𝐿𝐴𝑀𝐴𝑇𝐻+𝝎𝑺𝑫𝑫𝒕,𝒚 + 𝜔𝑂𝐿𝐷𝐴𝑝𝑟 2015 =1 +𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (7,1,0)(0,0,0)12

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 48 of 794
[25] Model notes:
1. POP is for Klamath County, OR.
Commercial Sector, Customers:

[26] 𝐶𝑡,𝑦,𝐾𝐿𝑀420.𝑐= 𝛽0 +𝛽1𝐶𝑡,𝑦,𝐾𝐿𝑀410.𝑟+ 𝝎𝑺𝑫𝑫𝒕,𝒚 + 𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2006=1 +𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (11,1,0)(1,0,0)12

[26] Model notes: 1. Ct,y,KLM410.r are residential customers from residential schedule 410. They are being used as a forecast driver because of the historical positive correlation between residential and commercial customer growth. See Tables 5.1 and 5.2. However, in as of the June 2019 forecast, the coefficient on Ct,y,KLM410.r is positive but no longer statistically significant. [27] 𝐶𝑡,𝑦,𝐾𝐿𝑀424.𝑐= 𝐶𝑦−1 +(𝛽0̂+𝛽1̂∆𝐸𝑀𝑃𝑦−1,4𝐶𝑜𝑢𝑛𝑡𝑦)

[27] Model notes:
1. This model reflects a recommendation by Oregon staff in the 2016 rate case to include employment as an economic driver for
schedule 424 commercial customers. The estimated equation in parenthesis reflects the regression estimated of ∆𝐶𝑦,𝐾𝐿𝑀424.𝑐=
𝛼0 +𝛼1∆𝐸𝑀𝑃𝑦−1,4𝐶𝑜𝑢𝑛𝑡𝑦+𝜀𝑡 using annual customer data since 2004. Annual data is used to smooth over the sometimes volatile
changes in the monthly customer number. In addition, customer increases and decreases around the long-run trend tend to occur
in steps. The combination of steps and month-to-month volatility creates significant economic problems when trying to model
around the monthly data. For example, even with intervention variables, tests for error normality always indicated non -normal error
terms with the use of monthly data.
2. ∆𝐶𝑦,𝐾𝐿𝑀424.𝑐 is the change in customers in year y (customer change between year y and y-1) and ∆𝐸𝑀𝑃𝑦−1,4𝐶𝑜𝑢𝑛𝑡𝑦 is the change
in total non-farm employment in Jackson, Josephine, Klamath, and Douglas counties in year y-1 (employment change between year
y-1 and y-2). Staff originally suggested lagged total employment for Oregon, but the correlation between schedule 424 customers
and employment for the three-county area is higher. The forecasted employment values for Jackson+Josephine County are derived
from the employment growth forecasts used in the Jackson+Josephine County population forecast. The forecasts for Douglas and
Klamath counties come from IHS. In IRP years, IHS forecasts for all counties will be used for the out years.
3. The annual forecast value for each year, F(∙), is assumed to hold for each month of that year. That is: 𝐹(𝐶𝑦,𝐾𝐿𝑀424.𝑐)=
𝐹(𝐶𝑡,𝑦,𝐾𝐿𝑀424.𝑐). Given the step-like behavior of the monthly series, this is a reasonable assumption.
4. The forecast and regressions for this schedule can be found in the Excel file folder “OR 4County Sch 424c Cus.” Industrial Sector, Customers: Industrial Sector, Customers:
[28] 𝐶𝑡,𝑦,𝐾𝐿𝑀420.𝑖= 1
12∑𝐶𝑡−𝑗12𝑗=1

[28] Model notes:
1. Data starts December 2006. The customer count fluctuates between 4 and 9 without any clear trend or seasonality.

[29] 𝐶𝑡,𝑦,𝐾𝐿𝑀424.𝑖= 1
12∑𝐶𝑡−𝑗12𝑗=1

[29] Model notes:
1. Data starts April 2009. The customer count fluctuates between 1 and 4 without any clear trend or seasonality.
10. La Grande, OR forecasting models:

The forecasting models for the La Grande region (Union County) are given below for the residential,
commercial, and industrial sectors:

Residential Sector, Customers:

[30] 𝐶𝑡,𝑦,𝐿𝑎𝐺410.𝑟= 𝜃0 +𝜃1𝑃𝑂𝑃𝑡,𝑦,𝑈𝑁𝐼𝑂𝑁+𝝎𝑺𝑫𝑫𝒕,𝒚+ 𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2004=1 +𝜔𝑂𝐿𝐷𝐽𝑢𝑙 2006=1 +𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2009=1+
𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (9,1,0)(1,0,0)12
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 49 of 794
[30] Model notes:
1. POP is population for Union County, OR. Commercial Sector, Customers:
[31] 𝐶𝑡,𝑦,𝐿𝑎𝐺424.𝑐= 1
12∑𝐶𝑡−𝑗12𝑗=1

[31] Model notes:
1. Data starts January 2007. The customer count fluctuates between 2 and 4 without any clear trend or seasonality. Changes in
the customer count appear as steps after prolonged periods of stability. Industrial Sector, Customers:
[7.32] 𝐶𝑡,𝑦,𝐿𝑎𝐺440.𝑖= 1
𝑁∑𝐶𝑡,𝑦−𝑗𝑁𝑗=1 𝑓𝑜𝑟 𝑦−𝑗=2012 ↑ 𝑢𝑝 𝑡𝑜 𝑡ℎ𝑒 𝑒𝑛𝑑 𝑜𝑓 𝑡ℎ𝑒 𝑛𝑒𝑎𝑟𝑒𝑠𝑡 𝑐𝑎𝑙𝑒𝑛𝑑𝑎𝑟 𝑦𝑒𝑎𝑟.

[7.32] Model notes:
1. Even in the presence of some seasonality, customer count can be highly erratic. Regression models produced poor diagnostics.
As a result, a historical monthly average is used as the forecast.
2. Restricted to 2012 ↑ because of a significant change in behavior starting in 2012. [7.31] 𝐶𝑡,𝑦,𝐿𝑎𝐺444.𝑖= 𝜃0 + 𝝎𝑺𝑫𝑫𝒕,𝒚+ 𝜔𝑂𝐿𝐷𝐴𝑢𝑔 2007=1 + 𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2009 =1 + 𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2010=1
+ 𝜔𝑂𝐿𝐷𝐴𝑢𝑔 2012 =1 + 𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2012 =1+ 𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2012=1+ 𝜔𝑂𝐿𝐷𝐽𝑎𝑛 2013 =1+ 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2013 =1+ 𝜔𝑂𝐿𝐷𝐽𝑎𝑛 2014 =1 +
𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2015 =1 +𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (10,0,0)(2,0,0)12
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 50 of 794
APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
WASHINGTON

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 51 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 52 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 53 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 54 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 55 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 56 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 57 of 794
APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
IDAHO

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 58 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 59 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 60 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 61 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 62 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 63 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 64 of 794
APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
MEDFORD

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 65 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 66 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 67 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 68 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 69 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 70 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 71 of 794
APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
ROSEBURG

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 72 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 73 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 74 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 75 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 76 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 77 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 78 of 794
APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
KLAMATH FALLS

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 79 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 80 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 81 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 82 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 83 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 84 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 85 of 794
APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
LA GRANDE

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 86 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 87 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 88 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 89 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 90 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 91 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 92 of 794
APPENDIX 2.3: DEMAND COEFFICIENTS

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 93 of 794
APPENDIX 2.3: WA BASE COEFFICIENT CALCULATION

APPENDIX 2.3: ID BASE COEFFICIENT CALCULATION

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 94 of 794
APPENDIX 2.3: MEDFORD BASE COEFFICIENT CALCULATION

APPENDIX 2.3: ROSEBURG BASE COEFFICIENT CALCULATION

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 95 of 794
APPENDIX 2.3: KLAMATH FALLS BASE COEFFICIENT
CALCULATION

APPENDIX 2.3: LA GRANDE BASE COEFFICIENT CALCULATION

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 96 of 794
APPENDIX 2.4: HEATING DEGREE DAY DATA MONTHLY TABLES

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 97 of 794

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Schedule 3a, Page 101 of 794
APPENDIX 2.4: AVERAGE HEATING DEGREE DAILY MONTH BY
AREA

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Schedule 3a, Page 106 of 794
APPENDIX 2.5: DEMAND SENSITIVITIES
SUMMARY OF ASSUMPTIONS – DEMAND SCENARIOS

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 107 of 794
APPENDIX 2.5: DEMAND SCENARIOS
PROPOSED SCENARIOS

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 108 of 794
APPENDIX 2.6: DEMAND FORECAST SENSITIVITIES AND
SCENARIOS DESCRIPTIONS
DEFINITIONS
DYNAMIC DEMAND METHODOLOGY – Avista’s demand forecasting approach wherein we 1)
identify key demand drivers behind natural gas consumption, 2) perform sensitivity analysis on
each demand driver, and 3) combine demand drivers under various scenarios to develop
alternative potential outcomes for forecasted demand.
DEMAND INFLUENCING FACTORS – Factors that directly influence the volume of natural gas
consumed by our core customers.
PRICE INFLUENCING FACTORS – Factors that, through price elasticity response, indirectly
influence the volume of natural gas consumed by our core customers.
REFERENCE CASE – A baseline point of reference that captures the basic inputs for determining
a demand forecast in SENDOUT® which includes number of customers, use per customer,
average daily weather temperatures and expected natural gas prices.
SENSITIVITIES – Focused analysis of a specific natural gas demand driver and its impact on
forecasted demand relative to the Reference Case when underlying input assumptions are
modified.
SCENARIOS – Combination of natural gas demand drivers that make up a demand forecast.
Avista evaluates each sensitivities impact.
SENSITIVITIES
The following Sensitivities were performed on identified demand drivers against the reference
case for consideration in Scenario development. Note that Sensitivity assumptions reflect
incremental adjustments we estimate are not captured in the underlying reference case
forecast.
Following are the Demand Influencing (Direct) Sensitivities we evaluated:
REFERENCE CASE – This benchmark case uses expected customer growth rates, the most
recent three years of actual use per customer per heating degree day data, average daily
temperature (HDDs) in the most recent 20 years in each region, no DSM, expected prices, and
no elasticity of demand.
REFERENCE CASE PLUS PEAK – Same assumptions as in the Reference Case with an
adjustment made to normal weather to incorporate peak weather conditions. The peak weather
data being the coldest day on record for each weather area.
LOW & HIGH CUSTOMER GROWTH – Same assumptions as in Reference Case Plus Peak with an
adjustment made to customer growth rates as discussed in detail in Appendix 2.1: Economic
Outlook and Customer Count Forecast.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 109 of 794
ALTERNATE WEATHER STANDARD (COLDEST DAY 20 YRS) – Same assumptions as in the
Reference Case with an adjustment made to normal weather to incorporate peak day weather
conditions. The peak day weather data reflecting the coldest average daily temperature (HDDs)
experienced in the most recent 20 years in each region.
DSM – Same assumptions as in Reference Case with the inclusion of Washington and Idaho
DSM potential identified by the Conservation Potential Assessment provided by Applied Energy
Group and Oregon DSM potential provided by Energy Trust of Oregon. See Appendix 3.1 for full
assessment reports.
PEAK PLUS DSM – Same assumptions as in Reference Case Plus Peak with the inclusion of
Washington and Idaho DSM potential identified by the Conservation Potential Assessment
provided by Applied Energy Group and Oregon DSM potential provided by Energy Trust of
Oregon. See Appendix 3.1 for full assessment reports.
80% BELOW 1990 EMISSIONS REFERENCE CASE – Reference Case Plus Peak assumptions
including reduction in Oregon and Washington consumption to 80% below 1990 emission levels
by 2050. The case shows the overall risk of a scenario with the overall goal of reducing natural
gas emissions but does not consider what methods will be used to get to these levels or their
costs.
ALTERNATE HISTORICAL 2-YEAR USE PER CUSTOMER – Reference Case Plus Peak use per
customer was based upon three years of actual use per customer per heating degree day data.
Same assumptions as in Reference Case Plus Peak with an adjustment made to use two years
of historical use per customer per heating degree day data.
ALTERNATE HISTORICAL 5-YEAR USE PER CUSTOMER – Reference Case Plus Peak use per
customer was based upon three years of actual use per customer per heating degree day data.
Same assumptions as in Reference Case Plus Peak with an adjustment made to use five years
of historical use per customer per heating degree day data.
JP OUTAGE AT 50% CAPACITY – Same assumptions as in Reference Case Plus Peak with
available transportation from Jackson Prairie storage field reduced to 50% of expected capacity.
AECO OUTAGE AT 50% CAPACITY – Same assumptions as in Reference Case Plus Peak with
available transportation from AECO reduced to 50% of expected capacity.
SUMAS OUTAGE AT 50% CAPACITY – Same assumptions as in Reference Case Plus Peak with
available transportation from Sumas reduced to 50% of expected capacity.
ROCKIES OUTAGE AT 50% CAPACITY – Same assumptions as in Reference Case Plus Peak with
available transportation from Rockies reduced to 50% of expected capacity.
GTN OUTAGE AT 50% CAPACITY – Same assumptions as in Reference Case Plus Peak with
available transportation on GTN reduced to 50% of expected capacity.
NWP OUTAGE AT 50% CAPACITY – Same assumptions as in Reference Case Plus Peak with
available transportation on NWP reduced to 50% of expected capacity.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 110 of 794
JP OUTAGE AT 0% CAPACITY – Same assumptions as in Reference Case Plus Peak with
available transportation from Jackson Prairie storage field reduced to 0% of expected capacity.
AECO OUTAGE AT 0% CAPACITY – Same assumptions as in Reference Case Plus Peak with
available transportation from AECO reduced to 0% of expected capacity.
SUMAS OUTAGE AT 0% CAPACITY – Same assumptions as in Reference Case Plus Peak with
available transportation from Sumas reduced to 0% of expected capacity.
ROCKIES OUTAGE AT 0% CAPACITY – Same assumptions as in Reference Case Plus Peak with
available transportation from Rockies reduced to 0% of expected capacity.
GTN OUTAGE AT 0% CAPACITY – Same assumptions as in Reference Case Plus Peak with
available transportation on GTN reduced to 0% of expected capacity.
NWP OUTAGE AT 0% CAPACITY – Same assumptions as in Reference Case Plus Peak with
available transportation on NWP reduced to 0% of expected capacity.
Following are the Price Influencing (Indirect) Sensitivities we evaluated:
EXPECTED ELASTICITY – For our Expected Elasticity Sensitivity, we incorporate reduced
consumption in response to higher natural gas prices by applying a price elasticity to demand.
See Price Elasticity in Chapter 2: Demand Forecasts for further detail.
LOW & HIGH PRICES – To capture a wide range of alternative price forecasts, we performed a
stochastic analysis based on the probability distribution of the expected price to develop 1,000
unique price forecasts around the expected price. Our high and low price forecasts represent
the 95th and 25th highest percentile in each month of the 1,000 resultant price forecasts,
respectively.
CARBON COST LOW CASE – Same assumptions as in Reference Case Plus Peak with
consideration for price elasticity including the cost of carbon. The price of carbon in Idaho,
Oregon, and Washington is set to $0 in all years.
CARBON COST EXPECTED CASE – The price of carbon in Oregon was based on a Wood
Mackenzie study for Cap and Trade. It begins with a 2021 price of $15.83 MTCO2e and rising to
$142.59 by 2045. The assumption is the cap and trade price will be similar to a cap and reduce
price. Rules for EO 20-04 are still being developed and will be included in the 2023 IRP.
Washington State was modeled using the required SCC @ 2.5%. This price is begins at $79.86
and increases yearly with a 2045 price of $185.75 (2019$). These values were provided by the
WUTC Staff and are per their assumptions on inflation.
CARBON COST HIGH CASE – Assumes the EPA estimates on the social cost of carbon.
Specifically, the high case includes 95% of results at a 3% discount rate average. These costs
begin at $112.20 in 2017 and increase to $174 by 2037 for a metric ton of CO2. This will
measure the risk of carbon pricing in all three jurisdictions.
Following are the Emissions Influencing Sensitivities we evaluated:
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 111 of 794
HIGH UPSTREAM EMISSIONS – Same assumptions as in Carbon Cost Expected Case with an
adjustment to upstream emissions. Expected upstream emissions are based on 0.79% methane
leakage. Per a study performed by the Environmental Defense Fund, high upstream emissions
are based on 2.47% methane leakage. Higher upstream emissions increase the associated cost
of carbon per dekatherm.
EXPECTED UPSTREAM EMISSIONS – Same assumption as in Carbon Cost Expected Case.
NO UPSTREAM EMISSIONS – Same assumptions as in Carbon Cost Expected Case with an
adjustment to upstream emissions. Expected upstream emissions are based on 0.79% methane
leakage. No upstream emissions are based on 0% methane leakage. Lower upstream
emissions decrease the associated cost of carbon per dekatherm.
20-YEAR GWP – Same assumptions as in Carbon Cost Expected Case with an adjustment to
the time period over which the energy absorbed by a gas is measured relative to CO2 and
converted into its Global Warming Potential. The time period of 100 years used for the expected
GWP is reduced to 20 years. The shorter lifetime of methane relative to CO2 results in a more
significant GWP when the measurement’s time period is reduced.
100-YEAR GWP – Same assumptions as in Carbon Cost Expected Case.

SCENARIOS
After identifying the above demand drivers and analyzing the various Sensitivities, we have
developed the following demand forecast Scenarios:
AVERAGE CASE – This Scenario we believe represents the most likely average demand forecast
modeled. We assume service territory customer growth rates consistent with the reference
case, rolling 20 year normal weather in each service territory, our expected natural gas price
forecast (blend of two consultants and the U.S. Energy Information Administration’s Annual
Energy Outlook, along with the NYMEX forward strip), expected price elasticity, the CO2 cost
adders from our Carbon Cost Expected Case Sensitivity, 100 year GWP, and DSM. The
Scenario does not include incremental cost adders for declining Canadian imports or drilling
restrictions beyond what is incorporated in the selected price forecast.
EXPECTED CASE – This Scenario represents the peak demand forecast. We assume service
territory customer growth rates consistent with the reference case, a weather standard of
coldest day on record in each service territory, our expected natural gas price forecast (blend of
two consultants and the U.S. Energy Information Administration’s Annual Energy Outlook, along
with the NYMEX forward strip), expected price elasticity, 100 year GWP, DSM, and the CO2
cost adders from our Carbon Cost Expected Case Sensitivity.
HIGH GROWTH, LOW PRICE – This Scenario models a rapid return to robust growth in part
spurred on by low energy prices. We assume higher customer growth rates than the reference
case, coldest day on record weather standard, our low natural gas price forecast, expected
price elasticity, 100 year GWP, DSM, and no CO2 adders.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 112 of 794
LOW GROWTH, HIGH PRICE – This Scenario models an extended period of slow economic growth
in part resulting from high energy prices. We assume lower customer growth rates than the
reference case, coldest day on record weather standard, our high natural gas price forecast,
expected price elasticity, 100 year GWP, DSM, and CO2 adders from our Carbon Cost High
Case Sensitivity.
80% BELOW 1990 EMISSIONS – This Scenario models the impact of potential consumption
curtailment due to carbon legislation coupled with low energy prices. We assume a straight line
reduction in Washington and Oregon consumption from reference case growth in order to meet
80% below 1990 emission levels by 2050, along with our low natural gas price forecast rather
than our expected natural gas price forecast. All other assumptions remain the same as our
Expected Case Scenario.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 113 of 794
APPENDIX 2.7: ANNUAL DEMAND, AVERAGE DAY DEMAND AND
PEAK DAY DEMAND (NET OF DSM) – CASE EXPECTED

APPENDIX 2.7: ANNUAL DEMAND, AVERAGE DAY DEMAND AND
PEAK DAY DEMAND (NET OF DSM) – CASE AVERAGE

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 114 of 794

APPENDIX 2.7: ANNUAL DEMAND, AVERAGE DAY DEMAND AND
PEAK DAY DEMAND (NET OF DSM) – CASE HIGH GROWTH

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 115 of 794
APPENDIX 2.7: ANNUAL DEMAND, AVERAGE DAY DEMAND AND
PEAK DAY DEMAND (NET OF DSM) – CASE LOW GROWTH

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 116 of 794
APPENDIX 2.7: ANNUAL DEMAND, AVERAGE DAY DEMAND AND
PEAK DAY DEMAND (NET OF DSM) - CARBON REDUCTION

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 117 of 794
APPENDIX 2.8: PEAK DAY DEMAND BEFORE AND AFTER DSM
WASHINGTON

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 118 of 794
APPENDIX 2.8: PEAK DAY DEMAND BEFORE AND AFTER DSM
IDAHO

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 119 of 794
APPENDIX 2.8: PEAK DAY DEMAND BEFORE AND AFTER DSM
MEDFORD/ROSEBURG

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 120 of 794
APPENDIX 2.8: PEAK DAY DEMAND BEFORE AND AFTER DSM
KLAMATH FALLS

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 121 of 794
APPENDIX 2.8: PEAK DAY DEMAND BEFORE AND AFTER DSM
LA GRANDE

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 122 of 794
APPENDIX 2.9: DETAILED DEMAND DATA
EXPECTED MIX

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 123 of 794

APPENDIX 2.9: DETAILED DEMAND DATA
LOW GROWTH HIGH PRICE

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 124 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 125 of 794

APPENDIX 2.9: DETAILED DEMAND DATA
HIGH GROWTH LOW PRICE

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Schedule 3a, Page 127 of 794

APPENDIX 2.9: DETAILED DEMAND DATA
AVERAGE MIX

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APPENDIX 2.9: DETAILED DEMAND DATA
CARBON REDUCTION

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 131 of 794

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Schedule 3a, Page 132 of 794

Energy Solutions. Delivered.

This work was performed by
Applied Energy Group, Inc.
211 Broad Street, Suite 206
Red Bank, NJ 07701
Executive-in-Charge: I. Rohmund
Report prepared for:
AVISTA UTILITIES

2020 AVISTA UTILITIES NATURAL GAS
CONSERVATION POTENTIAL ASSESSMENT
Volume 1, Final Report
De cember 1, 2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 133 of 794
This work was performed by:
Applied Energy Group, Inc.
500 Ygnacio Valley Road, Suite 250
Walnut Creek, CA 94596

Project Director: I. Rohmund
Project Manager: K. Walter

AEG would also like to acknowledge the valuable contributions of
Avista Utilities
1411 E Mission MSC-15 Spokane, WA 99220

Project Team: Ryan Finesilver James Gall
Leona Haley Tom Pardee

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 134 of 794
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 135 of 794
EXECUTIVE SUMMARY
Early in 2020, Avista Utilities (Avista) contracted with Applied Energy Group (AEG) to conduct this
Conservation Potential Assessment (CPA) in support of their conservation and resource planning activities.
This report documents this effort and provides estimates of the potential reductions in annual energy
usage for natural gas customers in Avista’s Washington and Idaho service territories from energy
conservation efforts in the time period of 2021 to 2040. To produce a reliable and transparent estimate of
energy efficiency (EE) resource potential, the AEG team performed the following tasks to meet Avista’s key
objectives:
• Used information and data from Avista, as well as secondary data sources, to describe how customers
currently use gas by sector, segment, end use and technology.
• Developed a baseline projection of how customers are likely to use gas in absence of future EE programs. This defines the metric against which future program savings are measured. This projection
used up-to-date technology data, modeling assumptions, and energy baselines that reflect both
current and anticipated federal, state, and local energy efficiency legislation that will impact energy
EE potential.
• Estimated the technical, achievable technical, and achievable economic potential at the measure level
for energy efficiency within Avista’s service territory over the 2021 to 2040 planning horizon.
• Delivered a fully configured end-use conservation planning model, LoadMAP, for Avista to use in
future potential and resource planning initiatives
In summary, the potential study provided a solid foundation for the development of Avista’s energy
savings targets.
Table ES-1 summarizes the results for Avista’s Washington territory at a high level. AEG analyzed potential
for the residential, commercial, and industrial market sectors. First-year utility cost test (UCT) achievable
economic potential in Washington is 75,820 dekatherms. This increases to a cumulative total of 173,838
dekatherms in the second year and 1,386,479 dekatherms by the tenth year (2030).
Table ES-1 Washington Conservation Potential by Case, Selected Years (dekatherms)
Scenario 2021 2022 2023 2030 2040
Baseline Forecast (Dth) 19,118,293 19,289,575 19,805,020 20,612,516 21,619,876
Cumulative Savings (Dth)
UCT Achievable Economic 75,820 173,838 457,423 1,386,479 3,560,512
Achievable Technical 41,871 416,584 1,221,810 3,183,398 6,309,826
Technical 187,983 897,098 2,314,334 5,084,999 8,908,493
Energy Savings (% of Baseline)
UCT Achievable Economic Potential 0.4% 0.9% 2.3% 6.7% 16.5%
Achievable Technical Potential 0.2% 2.2% 6.2% 15.4% 29.2%
Technical Potential 1.0% 4.7% 11.7% 24.7% 41.2%

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 136 of 794
Table ES-2 summarizes the results for Avista’s Idaho territory at a high level. First-year utility cost test
(UCT) achievable economic potential in Idaho is 35,816 dekatherms. This increases to a cumulative total
of 87,995 dekatherms in the second year and 737,710 dekatherms by the tenth year (2030).
Table ES-2 Idaho Conservation Potential by Case, Selected Years (dekatherms)
Scenario 2021 2022 2023 2030 2040
Baseline Forecast (Dth) 10,019,377 10,144,894 10,520,169 11,004,568 12,006,819
Cumulative Savings (Dth)
UCT Achievable Economic 35,816 87,995 229,283 737,710 2,025,410
Achievable Technical 26,220 226,613 657,997 1,722,830 3,544,048
Technical 102,031 490,826 1,273,202 2,777,509 5,013,697
Energy Savings (% of Baseline)
UCT Achievable Economic Potential 0.4% 0.9% 2.2% 6.7% 16.9%
Achievable Technical Potential 0.3% 2.2% 6.3% 15.7% 29.5%
Technical Potential 1.0% 4.8% 12.1% 25.2% 41.8%
As part of this study, we also estimated total resource cost (TRC) potential, with the focus of fully balancing
non-energy impacts. This includes the use of full measure costs as well as quantified and monetizable
non-energy impacts and non-gas fuel impacts (e.g. electric cooling or wood secondary heating) consistent
with methodology within the 2021 Northwest Conservation and Electric Power Plan (2021 Plan). We explore
this potential in more detail throughout the report.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 137 of 794
CONTENTS
Executiv e Summary ................................................................................................... i
1 INT RODUCTI ON ....................................................................................................... 1
Goals of the Conservation Potential Assessment......................................................... 1
Summary of Report Contents .................................................................................... 2
Abbreviations and Acronyms .................................................................................... 4
2 ANALYS IS APPROACH AND D ATA DEVEL OPMENT ................................................... 5
Ov erview of Analysis Approach................................................................................. 5
Comparison with Northwest Power & Conservation Council Methodology ........ 5
LoadMAP Model ........................................................................................... 6
Definitions of Potential................................................................................... 7
Market Characterization................................................................................ 9
Baseline Projection...................................................................................... 10
Energy Efficiency Measure Development...................................................... 11
Ca lculation of Energy Conservation Potential ............................................... 14
Data Development ................................................................................................ 16
Data Sources .............................................................................................. 16
Application of Data to the Analysis .............................................................. 19
3 MARKET CH ARACTE RIZATI O N AND M ARKET PROFILE S .......................................... 25
Ov erall Energy Use Summary ................................................................................... 25
Residential Sector .................................................................................................. 27
Washington Characterization ...................................................................... 27
Idaho Cha racterization ............................................................................... 29
Commercial Sector ................................................................................................ 32
Washington Characterization ...................................................................... 32
Idaho Cha racterization ............................................................................... 35
Industrial Sector ..................................................................................................... 38
Washington Characterization ...................................................................... 38
Idaho Characterization ............................................................................... 39
4 BASELI NE PRO JECTI ON ......................................................................................... 41
Ov erall Baseline Projection ..................................................................................... 42
Washington Projection ................................................................................ 42
Idaho Projection ......................................................................................... 43
Residential Sector .................................................................................................. 44
Washington Projection ................................................................................ 44
Idaho Projection ......................................................................................... 45
Commercial Sector ................................................................................................ 46
Washington Projection ................................................................................ 46
Idaho Projection ......................................................................................... 47
Industrial Sector ..................................................................................................... 48
Washington Projection ................................................................................ 48
Idaho Projection ......................................................................................... 49
5 OVE RAL L E NE RGY E FFICIE NCY POTENT IAL ........................................................... 50
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 138 of 794
Overall Energy Efficiency Potential .......................................................................... 50
Washington Potential .................................................................................. 50 Idaho Potential ........................................................................................... 54
6 SECTOR-LEVEL ENERGY EFFIC IE NCY POTE NTI AL ................................................... 57
Residential Sector .................................................................................................. 57
Washington Potential .................................................................................. 57
Idaho Potential ........................................................................................... 61
Commercial Sector ................................................................................................ 64
Washington Potential .................................................................................. 64
Idaho Potential ........................................................................................... 67
Industrial Sector ..................................................................................................... 70
Washington Potential .................................................................................. 70
Idaho Potential ........................................................................................... 73
Incorporating the Total Resource Cost Test .............................................................. 76
7 COMPARIS ON WITH C URRE NT PROGRAMS ........................................................... 77
Washington Comparison with 2019 Programs ........................................................... 77
Residential Sector ....................................................................................... 77
Commercial and Industrial Sectors ............................................................... 78
Idaho Comparison with 2019 Programs .................................................................... 79
Residential Sector ....................................................................................... 79
Commercial and Industrial Sectors ............................................................... 80
8 COMPARIS ON WITH PREVI OUS STUD Y .................................................................. 81
Residential Comparison with 2018 CPA .................................................................... 81
Nonresidential Comparison with 2018 CPA ............................................................... 81

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 139 of 794
LI ST OF FIGURES
Figure 1-1 Avista’s Serv ice Territory (courtesy Avista) ......................................................... 2
Figure 2-1 LoadMAP Analysis Framework........................................................................... 7
Figure 2-2 App roach for ECM Assessment ....................................................................... 12
Figure 3-1 Sector-Level Natural Gas Use in Base Year 2015, Washington (annual therms, percent)
.................................................................................................................... 25
Figure 3-2 Sector-Level Natural Gas Use in Base Year 2015, Idaho (annual therms, percent)26
Figure 3-3 Residential Natural Gas Use by Segment, Washington, 2015 ............................. 27
Figure 3-4 Residential Natural Gas Use by End Use, Washington, 2015 ............................... 28
Figure 3-5 Residential Energy Intensity by End Use and Segment, Washington, 2015 (Annual
Therms/HH).................................................................................................... 28
Figure 3-6 Residential Natural Gas Use by Segment, Idaho, 2015 ...................................... 30
Figure 3-7 Residential Natural Gas Use by End Use, Idaho, 2015........................................ 30
Figure 3-8 Residential Energy Intensity by End Use and Segment, Idaho, 2015 (Annual
Therms/HH).................................................................................................... 31
Figure 3-9 Commercial Natural Gas Use by Segment, Washington, 2015 ........................... 33
Figure 3-10 Commercial Sector Natural Gas Use by End Use, Washington, 2015................... 33
Figure 3-11 Commercial Energy Usage Intensity by End Use and Segment, Washington, 2015
(Annual Therms/Sq. Ft) ................................................................................... 34
Figure 3-12 Commercial Natural Gas Use by Segment, Idaho, 2015 .................................... 36
Figure 3-13 Commercial Sector Natural Gas Use by End Use, Idaho, 2015 ........................... 36
Figure 3-14 Commercial Energy Usage Intensity by End Use and Segment, Idaho, 2015 (Annual
Therms/Sq. Ft) ................................................................................................ 37
Figure 3-15 Industrial Natural Gas Use by End Use, Washington, 2015 .................................. 38
Figure 3-16 Industrial Natural Gas Use by End Use, Idaho, 2015........................................... 40
Figure 4-1 Baseline Projection Summary by Sector, Washington (dekatherms) ................... 42
Figure 4-2 Baseline Projection Summary by Sector, Idaho (dekatherms) ............................ 43
Figure 4-3 Residential Baseline Projection by End Use, Washington (dekatherms)............... 44
Figure 4-4 Residential Baseline Projection by End Use, Idaho (dekatherms) ....................... 45
Figure 4-5 Commercial Baseline Projection by End Use, Washington (dekatherms)............. 46
Figure 4-6 Commercial Baseline Projection by End Use, Idaho (dekatherms) ..................... 47
Figure 4-7 Industrial Baseline Projection by End Use, Washington (dekatherms).................. 48
Figure 4-8 Industrial Baseline Projection by End Use, Idaho (dekatherms) .......................... 49
Figure 5-1 Summary of Energy Efficiency Potential as % of Baseline Projection, Washington
(dekatherms)................................................................................................. 52
Figure 5-2 Baseline Projection and Energy Efficiency Forecasts, Washington (dekatherms) . 52
Figure 5-3 Cumulative UCT Achievable Economic Potential by Sector, Washington (% of Total)
.................................................................................................................... 53
Figure 5-4 Summary of Energy Efficiency Potential as % of Baseline Projection, Idaho
(dekatherms)................................................................................................. 55
Figure 5-5 Summary of Energy Efficiency Potential as % of Baseline Projection, Idaho
(dekatherms)................................................................................................. 55
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 140 of 794
Figure 5-6 Cumulativ e UCT Achievable Economic Potential by Sector, Idaho (% of Total) .. 56
Figure 6-1 Residential Energy Conservation by Case, Washington (dekatherms) ................ 57
Figure 6-2 Residential UCT Achievable Economic Potential – Cumulative Savings by End Use,
Wa shington (dekatherms, % of total)............................................................... 58
Figure 6-3 Residential Energy Conservation by Case, Idaho (dekatherms)......................... 61
Figure 6-4 Residential UCT Achievable Economic Potential – Cumulative Savings by End Use,
Ida ho (dekatherms, % of total) ....................................................................... 62
Figure 6-5 Commercial Energy Conservation by Case, Washington (dekatherms).............. 64
Figure 6-6 Commercial UCT Achievable Economic Potential – Cumulative Savings by End Use,
Wa shington (dekatherms, % of total)............................................................... 65
Figure 6-7 Commercial Energy Conservation by Case, Idaho (dekatherms) ...................... 67
Figure 6-8 Commercial UCT A chievable Economic Potential – Cumulative Savings by End Use,
Ida ho (dekatherms, % of total) ....................................................................... 68
Figure 6-9 Industrial Energy Conservation Potential, Washington (dekatherms) .................. 70
Figure 6-10 Industrial UCT Achievable Economic Potential – Cumulative Savings by End Use,
Wa shington (dekatherms, % of total)............................................................... 71
Figure 6-11 Industrial Energy Conservation Potential, Idaho (dekatherms)........................... 73
Figure 6-12 Industrial UCT Achievable Economic Potential – Cumulative Savings by End Use,
Ida ho (dekatherms, % of total) ....................................................................... 74

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 141 of 794
LIST OF TABLES
Table ES-1 Washington Conservation Potential by Case, Selected Years (dekatherms) .......... i
Table ES-2 Idaho Conservation Potential by Case, Selected Years (dekatherms).................. ii
Table 1-1 Explanation of Abbrev iations and Acronyms...................................................... 4
Table 2-1 Ov erview of Avista Analysis Segmentation Scheme............................................ 9
Table 2-2 Example Equipment Measures for Direct Fuel Furnace – Single-Family Home,
Washington ................................................................................................... 13
Table 2-3 Example Non-Equipment Measures – Existing Single Family Home, Washington... 14
Table 2-4 Number of Measures Evaluated ...................................................................... 14
Table 2-5 Data Applied for the Market Profiles ............................................................... 20
Table 2-6 Data Applied for the Baseline Projection in LoadMAP ...................................... 21
Table 2-7 Residential Natural Gas Equipment Federal Standards ..................................... 22
Table 2-8 Commercial and Industrial Natural Gas Equipment Standards .......................... 22
Table 2-9 Data Inputs for the Measure Characteristics in LoadMAP.................................. 23
Table 3-1 Avista Sector Control Totals, Washington, 2019 ................................................ 25
Table 3-2 Avista Sector Control Totals, Idaho, 2019 ......................................................... 26
Table 3-3 Residential Sector Control Totals, Washington, 2019 ......................................... 27
Table 3-4 Average Market Profile for the Residential Sector, Washington, 2019 ................. 29
Table 3-5 Residential Sector Control Totals, Idaho, 2019 .................................................. 29
Table 3-6 Average Market Profile for the Residential Sector, 2019 .................................... 31
Table 3-7 Commercial Sector Control Totals, Washington, 2019 ....................................... 32
Table 3-8 Average Market Profile for the Commercial Sector, Washington, 2019............... 34
Table 3-9 Commercial Sector Control Totals, Idaho, 2019 ................................................ 35
Table 3-10 Average Market Profile for the Commercial Sector, Idaho, 2019 ....................... 37
Table 3-11 Industrial Sector Control Totals, Washington, 2019 ............................................ 38
Table 3-12 Average Natural Gas Market Profile for the Industrial Sector, Washington, 2019 . 39
Table 3-13 Industrial Sector Control Totals, Idaho, 2019 ..................................................... 39
Table 3-14 Average Natural Gas Market Profile for the Industrial Sector, Idaho, 2019 .......... 40
Table 4-1 Baseline Projection Summary by Sector, Washington, Selected Years (dekatherms)
.................................................................................................................... 42
Table 4-2 Baseline Projection Summary by Sector, Idaho, Selected Years (dekatherms) .... 43
Table 4-3 Residential Baseline Projection by End Use, Washington (dekatherms)............... 44
Table 4-4 Residential Baseline Projection by End Use, Idaho (dekatherms) ....................... 45
Table 4-5 Commercial Baseline Projection by End Use, Washington (dekatherms)............. 46
Table 4-6 Commercial Baseline Projection by End Use, Idaho (dekatherms) ..................... 47
Table 4-7 Industrial Baseline Projection by End Use, Washington (dekatherms).................. 48
Table 4-8 Industrial Baseline Projection by End Use, Idaho (dekatherms) .......................... 49
Table 5-1 Summary of Energy Efficiency Potential, Washington (dekatherms) ................... 51
Table 5-2 Cumulative UCT Achievable Economic Potential by Sector, Washington, Selected
Years (dekatherms) ........................................................................................ 53
Table 5-3 Summary of Energy Efficiency Potential, Idaho (dekatherms)............................ 54
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 142 of 794
Tab le 5-4 Cumulative UCT Achievable Economic Potential by Sector, Idaho, Selected Years
(dekatherms)................................................................................................. 56
Tab le 6-1 Residential Energy Conservation Potential Summary, Washington (dekatherms). 57
Tab le 6-2 Residential Top Measures in 2021 and 2022, UCT Achievable Econ omic Potential,
Washington (dekatherms) .............................................................................. 60
Tab le 6-3 Residential Energy Conservation Potential Summary, Idaho (dekatherms) ......... 61
Tab le 6-4 Residential Top Measures in 2021 and 2022, UCT Achievable Economic Potential,
Idaho (dekatherms) ....................................................................................... 63
Tab le 6-5 Commercial Energy Conservation Potential Summary, Washington ................... 64
Tab le 6-6 Commercial Top Measures in 2021 and 2022, UCT Achievable Economic Potential,
Washington (dekatherms) .............................................................................. 66
Tab le 6-7 Commercial Energy Conservation Potential Summary, Idaho............................ 67
Tab le 6-8 Commercial Top Measures in 2021 and 2022, UCT Achievable Economic Potential,
Idaho (dekatherms) ....................................................................................... 69
Tab le 6-9 Industrial Energy Conservation Potential Summary, Washington (dekatherms) ... 70
Tab le 6-10 Ind ustrial Top Measures in 2021 and 2022, UCT Achievable Economic Potential,
Washington (dekatherms) .............................................................................. 72
Tab le 6-11 Industrial Energy Conservation Potential Summary, Idaho (dekatherms) ............ 73
Tab le 6-12 Ind ustrial Top Measures in 2018 and 2019, UCT Achievable Economic Potential, Idaho
(dekatherms)................................................................................................. 75
Tab le 7-1 Comparison of Avista’s Washington Residential Programs with 2018 UCT Achievable
Economic Potential (dekatherms) ................................................................... 77
Tab le 7-2 Comparison of Avista’s Washington Nonresidential Accomplishments with 2021 UCT
A chievable Economic Potential (dekatherms) ................................................. 78
Tab le 7-3 Comparison of Avista’s Idaho Residential Programs with 2021 UCT Achievable
Economic Potential (dekatherms) ................................................................... 79
Tab le 7-4 Comparison of Avista’s Idaho Nonresidential Accomplishments with 2021 UCT
A chievable Economic Potential (dekatherms) ................................................. 80
Tab le 8-1 Comparison of Avista’s Residential UCT Achievable Economic Potential between the
2016 and 2018 CPAs (dekatherms) .................................................................. 81
Tab le 8-2 Comparison of Avista’s Nonresidential UCT Achievable Economic Potential between
the 2016 and 2018 CPAs (dekatherms) ............................................................ 82

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 143 of 794
1
INTRODUCTION
This report documents the results of the Avista Utilities 2021-2040 Conservation Potential Assessment
(CPA) as well as the steps followed in its completion. Throughout this study, AEG worked with Avista to
understand the baseline characteristics of their service territory, including a detailed understanding of energy consumption in the territory, the assumptions and methodologies used in Avista’s official load
forecast, and recent programmatic accomplishments. Adapting methodologies consistent with the
Northwest Power and Conservation Council’s (Council’s) 2021 Power Plan1 for natural gas studies, AEG then developed an independent estimate of achievable, cost-effective EE potential within Avista’s service territory between 2021 and 2040.
Goals of the Conservation Potential Assessment
The first primary objective of this study was to develop independent and credible estimates of EE potential
achievably available within Avista’s service territory using accepted regional inputs and methodologies.
This included estimating technical, achievable technical, then achievable economic potential, using the
Council’s ramp rates as the starting point for all achievability assumptions, leveraging Northwest Energy
Efficiency Alliance’s (NEEA’s) market research initiatives, and utilizing assumptions consistent with 2021
Power Plan supply curves and RTF measure workbooks when appropriate for use in natural gas planning
studies.
Additionally, the CPA is intended to support the design of programs to be implemented by Avista during
the upcoming years. One output of the LoadMAP model is a comprehensive summary of measures. This
summary documents input assumptions and sources on a per-unit value, program applicability and
achievability (ramp rates), and potential results (units, incremental potential, and cumulative potential) as
well as cost-effectiveness at the UCT and TRC levels. This summary was developed in collaboration with Avista and refined throughout the project.
Finally, this study was developed to provide EE inputs into Avista’s Integrated Resource Planning (IRP) process. To this end, AEG developed detailed achievable economic EE inputs by measure for input into
Avista’s SENDOUT planning model under the utility cost test (UCT). These inputs are highly customizable
and provide potential estimates at the state level by measure and end use. We present a map of Avista’s
service territory in Figure 1-1.
1 “2021 Power Plan. Northwest Power & Conservation Council, 2020. https://www.nwcouncil.org/2021-northwest-power-plan
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 144 of 794
Figure 1-1 Avista’s Service Territory (courtesy Avista)

Summary of Report Contents
The document is divided into seven additional chapters, summarizing the approach, assumptions, and results of the EE potential analysis. We describe each section below:
Volume 1, Final Report:
• Analysis Approach and Data Development. Detailed description of AEG’s approach to conducting Avista’s 2021-2040 Natural Gas CPA and documentation of primary and secondary sources used.
• Market Characterization and Market Profiles. Characterization of Avista’s service territory in the base
year of the study, 2019, including total consumption, number of customers and market units, and
energy intensity. This also includes a breakdown of the energy consumption for residential, commercial, and eligible industrial customers by end use and technology.
• Baseline Projection. Projection of baseline energy consumption under a naturally occurring efficiency case, described at the end-use level. The LoadMAP models were first aligned with actual sales and
Avista’s official, weather-normalized econometric forecast and then varied to include the impacts of
future federal standards, ongoing impacts of energy codes, such as the 2015 Washington State Energy
Code on new construction, and future technology purchasing decisions.
• Overall Energy Efficiency Potential. Summary of EE potential for Avista’s Washington and Idaho service territories for selected years between 2021 and 2040.
• Sector-Level Energy Efficiency Potential. Summary of EE potential for each market sector within Avista’s
service territory, including residential, commercial, and eligible industrial customers for both
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 145 of 794
Washington and Idaho. This section includes a more detailed breakdown of potential by measure type,
vintage, market segment, end use, and state.
• Comparison with Current Programs Detailed comparison of potential with current Avista programs,
including new opportunities for potential.
• Comparison with 2018 CPA Detailed comparison of potential with Avista’s 2018 CPA, conducted by
AEG.
Volume 2, Appendices:
The appendices for this report are provided in separate spreadsheets accompanying delivery of this report
and consist of the following:
• Market Profiles. Detailed market profiles for each market segment. Includes equipment saturation,
unit energy consumption or energy usage index, energy intensity, and total consumption.
• Customer Adoption Factors. Documentation of the ramp rates used in this analysis. These were adapted from the 2021 Power Plan electrical power conservation supply curve workbooks for use in the estimation of achievable natural gas potential.
• Measure List. List of measures, along with example baseline definitions and efficiency options by market sector analyzed.
• Detailed Measure Assumptions. This dataset provides input assumptions, measure characteristics,
cost-effectiveness results, and potential estimates for each measure permutation analyzed within the
study.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 146 of 794
Abbreviations and Acronyms
Throughout the report we use several abbreviations and acronyms. Table 1-1 shows the abbreviation or
acronym, along with an explanation.
Table 1-1 Explanation of Abbreviations and Acronyms
Acronym Explanation
AEO Annual Energy Outlook forecast developed by EIA
B/C Ratio Benefit to Cost Ratio
BEST AEG’s Building Energy Simulation Tool
BPA Bonneville Power Administration
C&I Commercial and Industrial
CBSA NEEA’s 2019 Commercial Building Stock Assessment
Council Northwest Power and Conservation Council (NWPCC)
DHW Domestic Hot Water
DSM Demand Side Management
EE Energy Efficiency
EIA Energy Information Administration
EUL Estimated Useful Life
EUI Energy Usage Intensity
HVAC Heating Ventilation and Air Conditioning
IFSA NEEA’s 2014 Industrial Facilities Site Assessment
IRP Integrated Resource Plan
LoadMAP AEG’s Load Management Analysis and Planning™ tool
NEEA Northwest Energy Efficiency Alliance
O&M Operations and Maintenance
RBSA NEEA’s 2016 Residential Building Stock Assessment
RTF Regional Technical Forum
RVT Resource Value Test
TRC Total Resource Cost test
UCT Utility Cost Test
UEC Unit Energy Consumption
UES Unit Energy Savings
WSEC 2015 Washington State Energy Code

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 147 of 794
2
ANALYSIS APPROACH AND DATA DEVELOPMENT
This section describes the analysis approach taken for the study and the data sources used to develop the potential estimates.
Overview of Analysis Approach
To perform the potential analysis, AEG used a bottom-up approach following the major steps listed below.
We describe these analysis steps in more detail throughout the remainder of this chapter.
1. Performed a market characterization to describe sector-level natural gas use for the residential,
commercial, and industrial sectors for the base year, 2019. This included extensive use of Avista data and other secondary data sources from NEEA and the Energy Information Administration (EIA).
2. Developed a baseline projection of energy consumption by sector, segment, end use, and
technology for 2021 through 2040.
3. Defined and characterized several hundred EE measures to be applied to all sectors, segments, and
end uses.
4. Estimated technical, achievable technical, and achievable economic energy savings at the measure
level for 2021-2040. Achievable economic potential was assessed using both the UCT and TRC
screens.
Comparison with Northwest Power & Conservation Council Methodology
It is important to note the Council’s methodology was developed for, and used, in electric CPAs. Natural
gas impacts are typically assessed when they overlap with electricity measures (e.g. gas water heating
impacts in an electrically heated “Built Green Washington” home). The Council’s ramp rates were also developed with electric utility DSM programs in mind. Electricity is the primary focus of the regionwide
potential assessed in the Council’s Plans. Although Avista is a dual-fuel utility, this study focuses on natural
gas measures and programs, which exhibit noticeable differences from electric programs, notably regarding avoided costs. To account for this, AEG adapted Council methodologies in some cases, rather
than using them directly from the source. This is especially relevant in the development of ramp rates
when achievability was determined to not be applicable to a specific natural gas measure or program. We
discuss this in Section 7 of this report.
A primary objective of the study was to estimate natural gas potential consistent with the Northwest Power
& Conservation Council’s (NWPCC) analytical methodologies and procedures for electric utilities. While
developing Avista’s 2021-2040 CPA, the AEG team relied on an approach vetted and adapted through the
successful completion of CPAs under the Council’s Fifth, Sixth, Seventh, and now 2021 Power Plans. Among
other aspects, this approach involves using consistent:
• Data sources: Avista surveys, regional surveys, market research, and assumptions
• Measures and assumptions: Avista TRM, Seventh Plan supply curves and RTF work products
• Potential factors: 2021 Power Plan ramp rates
• Levels of potential: technical, achievable technical, and achievable economic
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 148 of 794
• Cost-effectiveness approaches: assessed potential under the UCT as well as Council’s TRC method,
including non-energy impacts (and non-gas energy impacts) which may be quantified and monetized
as well as O&M impacts within the TRC
• Conservation credits: applied a 10% conservation credit to avoided energy costs for energy benefits was applied to the TRC calculation
LoadMAP Model
For this analysis, AEG used its Load Management Analysis and Planning tool (LoadMAP™) version 5.0 to
develop both the baseline projection and the estimates of potential. AEG developed LoadMAP in 2007
and has enhanced it over time, using it for the EPRI National Potential Study and numerous utility-specific forecasting and potential studies since. Built in Excel, the LoadMAP framework (see Figure 2-1) is both
accessible and transparent and has the following key features.
• Embodies the basic principles of rigorous end-use models (such as EPRI’s Residential End-Use Energy
Planning System (REEPS) and Commercial End-Use Planning System (COMMEND)) but in a more simplified, accessible form.
• Includes stock-accounting algorithms that treat older, less efficient appliance/equipment stock separately from newer, more efficient equipment. Equipment is replaced according to the measure life and appliance vintage distributions defined by the user.
• Balances the competing needs of simplicity and robustness by incorporating important modeling
details related to equipment saturations, efficiencies, vintage, and the like, where market data are
available, and treats end uses separately to account for varying importance and availability of data resources.
• Isolates new construction from existing equipment and buildings and treats purchase decisions for
new construction and existing buildings separately. This is especially relevant in the state of
Washington where the 2015 WSEC substantially enhances the efficiency of the new construction
market.
• Uses a simple logic for appliance and equipment decisions. Other models available for this purpose
embody complex customer choice algorithms or diffusion assumptions, and the model parameters tend to be difficult to estimate or observe and sometimes produce anomalous results that require
calibration or even overriding. The LoadMAP approach allows the user to drive the appliance and
equipment choices year by year directly in the model. This flexible approach allows users to import the results from diffusion models or to input individual assumptions. The framework also facilitates
sensitivity analysis.
• Includes appliance and equipment models customized by end use. For example, the logic for water
heating is distinct from furnaces and fireplaces.
• Can accommodate various levels of segmentation. Analysis can be performed at the sector level (e.g.,
total residential) or for customized segments within sectors (e.g., housing type, state, or income level).
• Natively outputs model results in a detailed line-by-line summary file, allowing for review of input
assumptions, cost-effectiveness results, and potential estimates at a granular level. Also allows for the
development of IRP supply curves, both at the achievable technical and achievable economic potential
levels.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 149 of 794
• Consistent with the segmentation scheme and the market profiles we describe below, the LoadMAP
model provides projections of baseline energy use by sector, segment, end use, and technology for
existing and new buildings. It also provides forecasts of total energy use and energy-efficiency savings
associated with the various types of potential. 2
Figure 2-1 LoadMAP Analysis Framework

Definitions of Potential
Before we delve into the details of the analysis approach, it is important to define what we mean when discussing energy efficiency (EE) potential. In this study, the savings estimates are developed for three
types of potential: technical potential, economic potential, and achievable potential. These are developed
at the measure level, and results are provided as savings impacts over the 20-year forecasting horizon. The various levels are described below.
• Te chnical Potential is defined as the theoretical upper limit of EE potential. It assumes customers
adopt all feasible measures regardless of their cost. At the time of existing equipment failure,
customers replace their equipment with the most efficient option available. In new construction,
customers and developers also choose the most efficient equipment option.
o Technical potential also assumes the adoption of every other available measure, where technically
feasible. For example, it includes installation of high-efficiency windows in all new construction
opportunities and furnace maintenance in all existing buildings with installed furnaces. These
retrofit measures are phased in over a number of years to align with the stock turnover of related
equipment units, rather than modeled as immediately available all at once .
2 The model computes energy forecasts for each type of potential for each end use as an intermediate calculation. Annual-energy savings
are calculated as the difference between the value in the baseline projection and the value in the potential forecast (e.g., the technical
potential forecast).
Market Profiles
Base-Year Energy
Consumption
Projection Data
Energy-Efficiency
Analysis
Projection Results
Customer
segmentation
Market size
Equipment saturation
Technology shares Vintage distribution
Unit energy
consumption New construction
profile
By technology, end
use, segment, vintage,
sector, and state
Ec onomic Data
Customer growth
Energy prices
Elasticities & HDD65s
Technology Data Efficiency options
Codes and standards
Purchase shares
List of measures Saturations
Ramp rates
Avoided cost Cost-effectiveness
Baseline Projection
Energy-efficiency Projections
Technical
Achievable Technical
Achievable Economic
(UCT and TRC)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 150 of 794
• Ac h ievable Technical Potential refines technical potential by applying customer participation
rates that account for market barriers, customer awareness and attitudes, program maturity, and other
factors that affect market penetration of conservation measures. The customer adoption rates used
in this study were the ramp rates developed for the Northwest Power & Conservation Council’s Seventh Plan based on the electric-utility model, tailored for use in natural gas EE programs.
• U C T Achievable E conomic Potential further refines achievable technical potential by applying
an economic cost-effectiveness screen. In this analysis, primary cost-effectiveness is measured by the
utility cost test (UCT), which assesses cost-effectiveness from the utility’s perspective. This test compares lifetime energy benefits to the costs of delivering the measure through a utility program,
excluding monetized non-energy impacts. These costs are the incentive, as a percent of incremental
cost of the given efficiency measure, relative to the relevant baseline course of action (e.g. federal
standard for lost opportunity and no action for retrofits), plus any administrative costs that are
incurred by the program to deliver and implement the measure. If the benefits outweigh the costs
(that is, if the UCT ratio is greater than 1.0), a given measure is included in the economic potential.
• T R C Achievable E conomic Potential is similar to UCT achievable economic potential in that it
refines achievable technical potential through cost-effectiveness analysis. The total resource cost (TRC)
test assesses cost-effectiveness from a combined utility and participant perspective. As such, this test includes full measure costs but also includes non-energy impacts realized by the customer if
quantifiable and monetized. In addition to non-energy impacts, we assessed the impacts of non-gas
savings following Council methodology. This includes a calibration credit for space heating equipment consumption to account for secondary heating equipment present in an average home as well as
other electric end-use impacts such as cooling and interior lighting as applicable on a measure-by-
measure basis. As a secondary screen, we include TRC results for comparative purposes.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 151 of 794
Market Characterization
Now that we have described the modeling tool and provided the definitions of the potential cases, the
first step in the actual analysis approach is market characterization. To estimate the savings potential from energy-efficient measures, it is necessary to understand how much energy is used today and what
equipment is currently in service. This characterization begins with a segmentation of Avista’s natural gas
footprint to quantify energy use by sector, segment, end-use application, and the current set of
technologies in use. For this we rely primarily on information from Avista, augmenting with secondary
sources as necessary.
Segmentation for Modeling Purposes
This assessment first defined the market segments (states, building types, end uses, and other dimensions)
that are relevant in Avista’s service territory. The segmentation scheme for this project is presented in Table 2-1.
Table 2-1 Overview of Avista Analysis Segmentation Scheme
Dimension Segmentation Variable Description
0 State Washington and Idaho
1 Sector Residential, Commercial, Industrial
2 Segment
Residential: Single Family, Multifamily, Mobile Home, Low Income
Commercial: Office, Restaurant, Retail, Grocery, School, College,
Health, Lodging, Warehouse, Miscellaneous
Industrial
3 Vintage Existing and new construction
4 End uses Heating, secondary heating, water heating, food preparation, process,
and miscellaneous (as appropriate by sector)
5 Appliances/end uses and
technologies
Technologies such as furnaces, water heaters, and process heating by
application, etc.
6 Equipment efficiency levels
for new purchases
Baseline and higher-efficiency options as appropriate for each
technology
With the segmentation scheme defined, we then performed a high-level market characterization of natural
gas sales in the base year, 2019. This information provided control totals at a sector level for calibrating
the LoadMAP model to known data for the base-year.
Market Profiles
The next step was to develop market profiles for each sector, customer segment, end use, and technology.
A market profile includes the following elements:
• Ma r ket size is a representation of the number of customers in the segment. For the residential sector,
the unit we use is number of households. In the commercial sector, it is floor space measured in square
feet. For the industrial sector, it is number of employees.
• S a turations indicate the share of the market that is served by a particular end-use technology. Three
types of saturation definitions are commonly used:
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 152 of 794
o The conditioned space approach accounts for the fraction of each building that is conditioned by the end use. This applies to cooling and heating end uses.
o The whole-building approach measures shares of space in a building with an end use regardless
of the portion of each building that is served by the end use. Examples are commercial refrigeration and food service, and domestic water heating and appliances.
o The 100% saturation approach applies to end uses that are generally present in every building or
home and are simply set to 100% in the base year.
• U E C (Unit E nergy Consumption) or E UI (Energy U sage Index) define consumption for a
given technology. UEC represents the amount of energy a given piece of equipment is expected to
use in one year. EUI is a UEC indexed to a non-building market unit, such as per square foot or per employee)
• These are indices that refer to a measure of average annual energy use per market unit (home, floor
space, or employee in the residential, commercial, and industrial sector, respectively) that are served
by an end-use technology. UECs and EUIs embody an average level of service and average equipment
efficiency for the market segment.
• Ann ual e ne rgy intensity for the residential sector represents the average energy use for the
technology across all homes in 2015. It is computed as the product of the saturation and the UEC and
is defined as therms/household for natural gas. For the commercial and industrial sectors, intensity,
computed as the product of the saturation and the EUI, represents the average use for the technology
across all floor space or all employees in the base year.
• Ann ual u sage is the annual energy used by each end-use technology in the segment. It is the
product of the market size and intensity and is quantified in therms or dekatherms.
The market characterization results and the market profiles are presented in Section 3 and Appendix A.
Baseline Projection
The next step was to develop the baseline projection of annual natural gas use for 2021 through 2040 by customer segment and end use in the absence of new utility energy efficiency programs.
We first aligned with Avista’s official forecast. AEG incorporated assumptions and data utilized in the
official utility forecast. Avista’s heating degree days (base 65°F) were incorporated into the LoadMAP
model to align the baseline projection with the official utility forecast. We calibrated to actual sales when
available.
The end-use projection includes impacts of future federal standards that were effective as of December
2017, which drive energy consumption down through the study period.
Naturally occurring energy conservation, that is, energy conservation that is realized within the service
area independent of utility-sponsored programs, is incorporated into the baseline projection consistent
with the US Energy Information Administration’s Annual Energy Outlook for the Pacific region. Results of
the primary market research were used to calibrate these assumptions to ensure the secondary sources
were relevant to Avista customers. For example, some customers will purchase and install energy
conservation measures that are available in the market without a utility incentive.
As such, the baseline projection is the foundation for the analysis of savings in future conservation cases and scenarios as well as the metric against which potential savings are measured.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 153 of 794
Inputs to the baseline projection include:
• Current economic growth forecasts (i.e., customer growth, changes in weather (Heating Degree Day, base-65°F (HDD65) normalization))
• Trends in fuel shares and equipment saturations
• Existing and approved changes to building codes and equipment standards
We present the baseline projection results for the system as a whole, and for each sector in Section 4.
Energy Efficiency Measure Development
This section describes the framework used to assess the savings, costs, and other attributes of energy efficiency measures. These characteristics form the basis for measure-level cost-effectiveness analyses as
well as for determining measure-level savings. For all measures, AEG assembled information to reflect
equipment performance, incremental costs, and equipment lifetimes. This information combined with Avista’s avoided cost data informs the economic screens that determine economically feasible measures.
In this section, AEG would like to acknowledge the work of the Avista team in detailed measure
assumptions specific to the territory and region within the Avista TRM, which was provided at the outset
of this study.
Figure 2-2 outlines the framework for measure characterization analysis. First, the list of measures is
identified; each measure is then assigned an applicability for each market sector and segment and
characterized with appropriate savings, costs and other attributes; then the cost-effectiveness screening
is performed. Avista provided feedback during each step of the process to ensure measure assumptions and results lined up with programmatic experience.
We compiled a robust list of conservation measures for each customer sector, drawing upon Avista’s TRM
and program experience, AEG’s own measure databases and building simulation models, and secondary
sources, primarily the Regional Technical Forum’s (RTF) UES measure workbooks and the Seventh Plan’s
electric power conservation supply curves. This universal list of measures covers all major types of end-use equipment, as well as devices and actions to reduce energy consumption.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 154 of 794
Figure 2-2 Approach for ECM Assessment

The selected measures are categorized into two types according to the LoadMAP modeling taxonomy:
equipment measures and non-equipment measures.
• E q uipment measures are efficient energy-consuming pieces of equipment that save energy by
providing the same service with a lower energy requirement than a standard unit. An example is an
ENERGY STAR® residential water heater (UEF 0.64) that replaces a standard efficiency water heater
(UEF 0.58). For equipment measures, many efficiency levels may be available for a given technology,
ranging from the baseline unit (often determined by a code or standard) up to the most efficient
product commercially available. These measures are applied on a stock-turnover basis, and in general, are referred to as lost opportunity (LO) measures by the Council because once a purchase decision is
made, there will not be another opportunity to improve the efficiency of that equipment item until its
effective useful life (EUL) is reached once again.
• N on-equipment measure s save energy by reducing the need for delivered energy, but do not necessarily involve replacement or purchase of major end-use equipment (such as a furnace or water
heater). Measure installation is not tied to a piece of equipment reaching end of useful life, so these
are generally categorized as “retrofit” measures. An example would be low-flow showerheads that
modify a household’s hot water consumption. The existing showerheads can be achievably replaced
without waiting for the existing showerhead to malfunction, and saves energy used by the water
heating equipment. Non-equipment measures typically fall into one of the following categories:
o Building shell (windows, insulation, roofing material)
o Equipment controls (smart thermostats, water heater setback)
o Whole-building design (ENERGY STAR homes)
AEG universal
measure list Client review / feedback
Measure
descriptions
Measure characterization
Economic screen
UCT and TRC
Energy savings Costs and NEIs
Lifetime Base saturation and
applicability
Client measure
data library
(RTF, 7th Plan, AEO, Statewide
TRMs, evaluation reports, etc.)
AEG measure
data library
(DEEM)
Building Simulations
Avoided costs, discount rate,
transport losses
Inputs Process
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 155 of 794
o Retrocommissioning and strategic energy management
We developed a preliminary list of efficient measures, which was distributed to Avista’s project team for
review. Once we assembled the list of measures, the AEG team assessed their energy-saving
characteristics. For each measure, we also characterized incremental cost, service life, non-energy impacts,
and other performance factors. Following the measure characterization, we performed an economic
screening of each measure, which serves as the basis for developing the economic and achievable
potential scenarios.
Representative Measure Data Inputs
To provide an example of measure data, Table 2-2 and Table 2-3 present examples of the detailed data
inputs behind both equipment and non-equipment measures, respectively, for the case of residential
direct-fuel furnaces in single-family homes in Washington. Table 2-2 displays the various efficiency levels
available as equipment measures, as well as the corresponding effective useful life, energy usage, and
cost estimates. The columns labeled “On Market” and “Off Market” reflect equipment availability due to codes and standards or the entry of new products to the market.
Table 2-2 Example Equipment Measures for Direct Fuel Furnace – Single-Family Home, Washington
Efficiency Level Useful Life
(years)
Equipment
Cost
Energy Usage
(therms/yr)
On
Market
Off
Market
AFUE 80% 20 $1,955 517 2019 2023
AFUE 90% 20 $2,058 465 2019 2023
AFUE 92% 20 $2,099 453 2019 n/a
AFUE 95% 20 $2,778 438 2019 n/a
AFUE 98% 20 $3,035 423 2019 n/a
Convert to NG Heat Pump 20 $6,739 345 2019 n/a
Table 2-3 lists some of the non-equipment measures applicable to a direct-fuel furnace in an existing
single-family home. All measures are evaluated for cost effectiveness based on the lifetime benefits
relative to the cost of the measure. The total savings, costs, and monetized non-energy impacts are
calculated for each year of the study and depend on the base year saturation of the measure, the
applicability of the measure, and the savings as a percentage of the relevant energy end uses. We model
two flavors of most shell insulations measures. The first is the installation of insulation where there is none
(or very little). This applies to a small subset of the population (roughly 7% of the population is eligible
for this measure per RBSA 2016) but has large savings impacts. This percentage is low due to the impacts
of current Avista programs, strict Washington building codes, and naturally occurring efficiency. The second is an insulation upgrade measure where homes with existing insulation below the threshold but
not classified as no insulation, may be upgraded to higher R-values. This applies to a much larger
percentage of the market.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 156 of 794
Table 2-3 Example Non-Equipment Measures – Existing Single Family Home, Washington3
End Use Measure Saturation
in 20194 Applicability Lifetime
(yrs)
Measure
Installed Cost
Energy
Savings (%)
Heating Insulation - Ceiling
Installation 0% 7% 45 $1,280 31.3%
Heating Insulation – Ceiling Upgrade 78% 87% 45 $1,739 1.2%
Heating Ducting Repair and Sealing 20% 50% 20 $794 6.0%
Heating Windows - High Efficiency5 0% 25% 45 $5,337 25.5%
Table 2-4 summarizes the number of measures evaluated for each segment within each sector.
Table 2-4 Number of Measures Evaluated
Sector Total Measures Measure Permutations
w/ 2 Vintages
Measure Permutations
w/ All Segments & States
Residential 46 92 736
Commercial 51 102 2,040
Industrial 30 60 120
Total Measures Evaluated 127 254 2,896
Calculation of Energy Conservation Potential
The approach we used for this study to calculate the energy conservation potential adheres to the
approaches and conventions outlined in the National Action Plan for Energy-Efficiency (NAPEE) Guide for
Conducting Potential Studies.6 This document represents credible and comprehensive industry best practices for specifying energy conservation potential. Three types of potential were developed as part of
this effort: technical potential, achievable technical potential, and achievable economic potential (using
UCT and TRC). The calculation of technical potential is a straightforward algorithm which, as described above, assumes that customers adopt all feasible measures regardless of their cost.
Stacking of Measures and Interactive Effects
An important factor when estimating potential is to consider interactions between measures when they are applied within the same space. This is important to avoid double counting and could feasibly result in
savings at greater than 100% of equipment consumption if not properly accounted for.
This occurs at the population or system level, where multiple DSM actions must be stacked or layered on
top of each other in succession, rather than simply summed arithmetically. These interactions are
automatically handled within the LoadMAP models where measure impacts are stacked on top of each
3 The applicability factors consider whether the measure is applicable to a particular building type and whether it is feasible to install the
measure. For instance, duct repair and sealing is not applicable to homes with zonal heating systems since there is no ductwork present
to repair.
4 Note that saturation levels reflected increase from their base year saturation as more measures are adopted.
5 The RTF has increased the efficiency requirements for what is considered a “high efficiency” window for the purpose of future programs.
As a result, no respondents to the 2016 RBSA have windows that already meet this threshold. However, the qualified savings in the RTF
workbook require a certain level of inefficiency in the pre-existing window to be eligible. The 25% applicability reflects the population that
is eligible to participate.
6 National Action Plan for Energy Efficiency (2007). National Action Plan for Energy Efficiency Vision for 2025: Developing a Framework for
Change. www.epa.gov/eeactionplan.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 157 of 794
other, modifying the baseline for each subsequent measure. We first compute the total savings of each
measure on a standalone basis, then also assign a stacking priority, based on levelized cost, to the
measures such that “integrated” or “stacked” savings will be calculated as a percent reduction to the
running total of baseline energy remaining in each end use after the previous measures have been applied.
This ensures that the available pie of baseline energy shrinks in proportion to the number of DSM
measures applied, as it would in reality. The loading order is based on the levelized cost of conserved
energy, such that the more economical measures that are more likely to be selected from a resource
planning perspective will be the first to be applied to the modeled population.
We also account for exclusivity of certain measure options when defining measure assumptions. For
instance, if an AFUE 95% furnace is installed in a single-family home, the model will not allow that same home to install an AFUE 98% furnace, or any other furnace, until the newly installed AFUE 95% option has
reached its end of useful life. For non-equipment measures, which do not have a native applicability limit,
we define base saturations and applicabilities such that measures do not overlap. For example, we model two flavors of ceiling insulation. The first assumes the installation of insulation where there previously was
none. The second upgrades pre-existing insulation if it falls under a certain threshold. We used regional
market research data to ensure exclusivity of these two options. NEEA’s 2014 RBSA contains information on average R-values of insulation installed. The AEG team used this data to define the percent of homes that could install one measure, but not the other.
Estimating Customer Adoption
Once the technical potential is established, estimates for the market adoption rates for each measure are
applied that specify the percentage of customers that will select the highest–efficiency economic option.
This phases potential in over a more realistic time frame that considers barriers such as imperfect
information, supplier constraints, technology availability, and individual customer preferences. The intent
of market adoption rates is to establish a path to full market maturity for each measure or technology
group and ensure resource planning does not overstep acquisition capabilities. We adapted the Northwest
Power and Conservation Council’s 2021 Plan ramp rates to develop these achievability factors for each
measure. Applying these ramp rates as factors leads directly to the achievable technical potential.
Screening Measures for Cost-Effectiveness
With achievable technical potential established, the final step is to apply an economic screen and arrive
at the subset of measures that are cost-effective and ultimately included in achievable economic potential.
LoadMAP performs an economic screen for each individual measure in each year of the planning horizon.
This study uses the UCT test as the primary cost-effectiveness metric, which compares the lifetime hourly
energy benefits of each applicable measure with the incentive and administrative costs incurred by the
utility. The lifetime benefits are calculated by multiplying the annual energy savings for each measure by
Avista’s avoided costs and discounting the dollar savings to the present value equivalent. Lifetime costs
represent incremental measure cost. The analysis uses each measure’s values for savings, costs, and lifetimes that were developed as part of the measure characterization process described above.
The LoadMAP model performs this screening dynamically, considering changing savings and cost data
over time. Thus, some measures pass the economic screen for some, but not all, of the years in the
forecast.
It is important to note the following about the economic screen:
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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• The economic evaluation of every measure in the screen is conducted relative to a baseline condition. For instance, in order to determine the therm savings potential of a measure,
consumption with the measure applied must be compared to the consumption of a baseline
condition.
• The economic screening was conducted only for measures that are applicable to each building type and vintage; thus, if a measure is deemed to be irrelevant to a building type and vintage, it is excluded from the respective economic screen.
This constitutes the achievable economic potential and includes every program-ready opportunity for
conservation savings. Potential results are presented in Sections 4 and 5. Measure-level detail is available
as a separate appendix to this report.
Data Development
This section details the data sources used in this study, followed by a discussion of how these sources
were applied. In general, data were adapted to local conditions, for example, by using local sources for
measure data and local weather for building simulations.
Data Sources
The data sources are organized into the following categories:
• Avista-provided data
• AEG’s databases and analysis tools
• Other secondary data and reports
Avista Data
Our highest priority data sources for this study were those that were specific to Avista, including the
primary market research conducted specifically for this study. This data is specific to Avista’s service
territory and is an important consideration when customizing the model for Avista’s market. This is best practice when developing CPA baselines when the data is available.
• Av i sta cu stomer a ccount d atabase. Avista provided billing data for development of customer counts and energy use for each sector. This included a very detailed database of customer building
classifications which was instrumental in the development of segmentation.
• Avista’s 2013 GenPOP Residential Survey. In 2013, Avista hired The Cadmus Group to conduct a
residential saturation survey, which included results from 1,051 customers. The results of this survey helped segment the residential sector and establish fuel and technology shares for the base year. This
data was very useful in developing a detailed estimate of energy consumption within Avista’s service
territory.
• Load forecasts. Avista provided forecasts, by sector and state, of energy consumption, customer
counts, weather actuals for 2015 and 2017, as well as weather-normal HDD65s.
• E c onomic information. Avista provided a discount rate as well as avoided cost forecasts consistent with those utilized in the IRP.
• Av i sta program d ata. Avista provided information about past and current programs, including program descriptions, goals, and measure achievements to date.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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• Av i sta T R M. Avista provided a documented list of energy conservation measures and assumptions
considered within current programs. We utilized this as a primary source of measure information, supplemented by Northwest data, AEG data, and secondary data as described below.
Northwest Regional Data
The study utilized a variety of local data and research, including research performed by the Northwest
Energy Efficiency Alliance (NEEA) and analyses conducted by the Council. Most important among these
are:
• Northwest Power and Conservation Council, 2021 Power Plan and Regional Technical Forum
workbooks. To develop its Power Plan, the Council maintains workbooks with detailed information
about measu res. This was used as a primary data source when Avista-specific program data was not
available, and the data was determined to be applicable to natural gas conservation measures. The
most recent data and workbooks available were used at the time of this study.
o https://www.nwcouncil.org/2021-northwest-power-plan
o https://rtf.nwcouncil.org/measures
• N orthwest Energy Efficiency Alliance, 2011 Residential Building Stock Assessment
S ingle-Family, Market Research Report, http://neea.org/docs/reports/residential-building-stock-
assessment-single-family-characteristics-and-energy-use.pdf?sfvrsn=8
• N orthwest Energy Efficiency Al liance, 2014 Commercial Building Stock Assessment,
December 16, 2014, http://neea.org/docs/default-source/reports/2014-cbsa-final-report_05-dec-2014.pdf?sfvrsn=12.
• N orthwest Energy Efficiency Alliance, 2014 Industrial F acilities S ite Assessment,
December 29, 2014, http://neea.org/resource-center/regional-data-resources/industrial-facilities-
site-assessment
Since Avista’s GenPOP survey contained detailed appliance saturations, the RBSA was used more for
benchmarking and comparative purposes, rather than as a primary source of data. The NEEA surveys were
used extensively to develop base saturation and applicability assumptions for many of the non-equipment measures within the study.
AEG Data
AEG maintains several databases and modeling tools that we use for forecasting and potential studies.
Relevant data from these tools has been incorporated into the analysis and deliverables for this study.
• AEG E nergy Ma rket Profiles. For more than 10 years, AEG staff has maintained profiles of end-
use consumption for the residential, commercial, and industrial sectors. These profiles include market
size, fuel shares, unit consumption estimates, and annual energy use by fuel (natural gas and
electricity), customer segment and end use for 10 regions in the U.S. The Energy Information
Administration surveys (RECS, CBECS and MECS) as well as state-level statistics and local customer
research provide the foundation for these regional profiles.
• Bu i lding E nergy S imulation Tool (BEST). AEG’s BEST is a derivative of the DOE 2.2 building
simulation model, used to estimate base-year UECs and EUIs, as well as measure savings for the HVAC-
related measures.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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• AEG’s Da tabase of E n e rgy Conservation Measures (DEEM). AEG maintains an extensive
database of measure data for our studies. Our database draws upon reliable sources including the
California Database for Energy Efficient Resources (DEER), the EIA Technology Forecast Updates –
Residential and Commercial Building Technologies – Reference Case, RS Means cost data, and
Grainger Catalog Cost data.
• R ecent s tudies. AEG has conducted more than 60 studies of EE potential in the last five years. We
checked our input assumptions and analysis results against the results from these other studies, both
within the region and across the country.
Other Secondary Data and Reports
Finally, a variety of secondary data sources and reports were used for this study. The main sources are identified below.
• Ann ual E nergy Outlook. The Annual Energy Outlook (AEO), conducted each year by the U.S. Energy Information Administration (EIA), presents yearly projections and analysis of energy topics. For
this study, we used data from the 2015 and 2017 AEO.
• Am e rican Community Survey. The US Census American Community Survey is an ongoing survey
that provides data every year on household characteristics. http://www.census.gov/acs/www/
• Local We ather Da ta. Weather from NOAA’s National Climatic Data Center for Spokane in
Washington and Coure d’Alene in Idaho were used where applicable.
• E P RI E nd-Use Models (R EEPS a nd COMMEND). These models provide the energy-use
elasticities we apply to prices, household income, home size, heating, and cooling.
• Da tabase for E nergy E fficient R esources (DEER). The California Energy Commission and
California Public Utilities Commission (CPUC) sponsor this database, which is designed to provide
well-documented estimates of energy and peak demand savings values, measure costs, and effective
useful life (EUL) for the state of California. We used the DEER database to cross check the measure
savings we developed using BEST and DEEM.
• Ot h er re levant resources: These include reports from the Consortium for Energy Efficiency, the
EPA, and the American Council for an Energy-Efficient Economy. This also includes technical reference
manuals (TRMs) from other states. When using data from outside the region, especially weather-
sensitive data, AEG adapted assumptions for use within Avista’s territory.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Application of Data to the Analysis
We now discuss how the data sources described above were used for each step of the study.
Data Application for Market Characterization
To construct the high-level market characterization of natural gas consumption and market size units
(households for residential, floor space for commercial, and employees for industrial), we primarily used Avista’s billing data as well as secondary data from AEG’s Energy Market Profiles database.
Data Application for Market Profiles
The specific data elements for the market profiles, together with the key data sources, are shown in Table 2-5. To develop the market profiles for each segment, we used the following approach:
1. Develop control totals for each segment. These include market size, segment-level annual natural gas
use, and annual intensity. Control totals were based on Avista’s actual sales and customer-level
information found in Avista’s customer billing database. We used the market profiles from the 2016 CPA as a starting point.
2. Develop existing appliance saturations and the energy characteristics of appliances, equipment, and
buildings using equipment flags within Avista’s billing data, NEEA’s 2016 RBSA, 2019 CBSA, and 2014
IFSA, DOE’s 2015 RECS, the 2019 edition of the Annual Energy Outlook, AEG’s Energy Market Profile
(EMP) for the Pacific region, and the American Community Survey.
3. Ensure calibration to Avista control totals for annual natural gas sales in each sector and segment.
4. Compare and cross-check with other recent AEG studies.
5. Work with Avista staff to verify the data aligns with their knowledge and experience.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 162 of 794
Table 2-5 Data Applied for the Market Profiles
Model Inputs Description Key Sources
Market size Base-year residential dwellings, commercial
floor space, and industrial employment
Avista 2019 actual sales
Avista customer account database
Annual intensity
Residential: Annual use per household
Commercial: Annual use per square foot
Industrial: Annual use per employee
Avista customer account database
AEG’s Energy Market Profiles
AEO 2019 – Pacific Region
Other recent studies
Appliance/equipment
saturations
Fraction of dwellings with an
appliance/technology
Percentage of C&I floor space/employment
with equipment/technology
Avista 2013 GenPOP Survey
2016 RBSA, 2019 CBSA and IFSA
2018 American Community Survey
AEG’s Energy Market Profiles
UEC/EUI for each end-use
technology
UEC: Annual natural gas use in homes and
buildings that have the technology
EUI: Annual natural gas use per square
foot/employee for a technology in floor space
that has the technology
HVAC uses: BEST simulations using
prototypes developed for Avista
Engineering analysis
AEG DEEM
AEO 2019 – Pacific Region
Recent AEG studies
Appliance/equipment age
distribution Age distribution for each technology 2016 RBSA, 2019 CBSA, and recent
AEG studies
Efficiency options for each
technology
List of available efficiency options and annual
energy use for each technology
Avista current program offerings
AEG DEEM
AEO 2019
CA DEER
Recent AEG studies

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 163 of 794
Data Application for Baseline Projection
Table 2-6 summarizes the LoadMAP model inputs required for the baseline projection. These inputs are
required for each segment within each sector, as well as for new construction and existing dwellings/buildings.
Table 2-6 Data Applied for the Baseline Projection in LoadMAP
Model Inputs Description Key Sources
Customer growth forecasts Forecasts of new construction in
residential and C&I sectors Avista load forecast
Equipment purchase shares
for baseline projection
For each equipment/technology,
purchase shares for each efficiency
level; specified separately for existing
equipment replacement and new
construction
Shipment data from AEO and ENERGY STAR
AEO 2019 regional forecast assumptions7
Appliance/efficiency standards analysis
Utilization model
parameters
Price elasticities, elasticities for other
variables (income, weather) EPRI’s REEPS and COMMEND models
In addition, assumptions were incorporated for known future equipment standards as of June 2020, as shown in Table 2-7 and Table 2-8. The assumptions tables here extend through 2025, after which all
standards are assumed to hold steady.

7 We developed baseline purchase decisions using the Energy Information Agency’s Annual Energy Outlook report (2017), which utilizes
the National Energy Modeling System (NEMS) to produce a self-consistent supply and demand economic model. We calibrated equipment
purchase options to match distributions/allocations of efficiency levels to manufacturer shipment data for recent years.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 164 of 794
Table 2-7 Residential Natural Gas Equipment Federal Standards8
End Use Technology 2019 2020 2021 2022 2023 2024 2025
Space Heating
Furnace – Direct Fuel AFUE 80% AFUE 92%*
Boiler – Direct Fuel AFUE 82% AFUE 84%
Secondary Heating Fireplace N/A
Water Heating
Water Heater <= 55 gal. UEF 0.58
Water Heater > 55 gal. UEF 0.76
Appliances
Clothes Dryer CEF 3.30
Stove/Oven N/A
Miscellaneous
Pool Heater TE 0.82
Miscellaneous N/A
* This code was originally set to take effect in 2021 but exempts smaller systems. The comment period was also extended into 2017 and the
standard will not take effect until at least 5 years after that has concluded. As a result, we modeled this standard c oming online officially in 2024.

Table 2-8 Commercial and Industrial Natural Gas Equipment Standards
End Use Technology 2019 2020 2021 2022 2023 2024 2025
Cooling
Furnace AFUE 80% / TE 0.80
Boiler Average around AFUE 80% / TE 0.80 (varies by size)
Unit Heater Standard (intermittent ignition and power venting or automatic flue damper)
Water Heater Water Heating TE 0.80

8 The assumptions tables here extend through 2025, after which all standards are assumed to hold steady.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 165 of 794
Energy Conservation Measure Data Application
Table 2-9 details the energy-efficiency data inputs to the LoadMAP model. It describes each input and
identifies the key sources used in the Avista analysis.
Table 2-9 Data Inputs for the Measure Characteristics in LoadMAP
Model Inputs Description Key Sources
Energy Impacts
The annual reduction in consumption attributable to each
specific measure. Savings were developed as a
percentage of the energy end use that the measure
affects.
Avista TRM
NWPCC workbooks, RTF
AEG BEST
AEG DEEM
AEO 2019
CA DEER
Other secondary sources
Costs
Equipment Measures: Includes the full cost of purchasing
and installing the equipment on a per-household, per-
square-foot, or per employee basis for the residential,
commercial, and industrial sectors, respectively.
Non-Equipment Measures: Existing buildings – full
installed cost. New Construction - the costs may be either
the full cost of the measure, or as appropriate, it may be
the incremental cost of upgrading from a standard level
to a higher efficiency level.
Avista TRM
NWPCC workbooks, RTF
AEG DEEM
AEO 2019
CA DEER
RS Means
Other secondary sources
Measure Lifetimes
Estimates derived from the technical data and secondary
data sources that support the measure demand and
energy savings analysis.
Avista TRM
NWPCC workbooks, RTF
AEG DEEM
AEO 2019
CA DEER
Other secondary sources
Applicability
Estimate of the percentage of dwellings in the residential
sector, square feet in the commercial sector, or
employees in the industrial sector where the measure is
applicable and where it is technically feasible to
implement.
2016 RBSA, 2019 CBSA
2015 WSEC for limitations on new
construction
AEG DEEM
CA DEER
Other secondary sources
On Market and Off
Market Availability
Expressed as years for equipment measures to reflect
when the equipment technology is available or no longer
available in the market.
AEG appliance standards and
building codes analysis

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 166 of 794
Data Application for Cost-effectiveness Screening
To perform the cost-effectiveness screening, a number of economic assumptions were needed. All cost
and benefit values were analyzed as real dollars, converted from nominal provided by Avista. We applied
Avista’s long-term discount rate of 4.34% excluding inflation. LoadMAP is configured to vary this by market
sector (e.g. residential and commercial) if Avista develops alternative values in the future.
Estimates of Customer Adoption
To estimate the timing and rate of customer adoption in the potential forecasts, two sets of parameters
are needed:
• Te chnical d iffusion curves for non-equipment measures. Equipment measures are installed
when existing units fail. Non-equipment measures do not have this natural periodicity, so rather than
installing all available non-equipment measures in the first year of the projection (instantaneous
potential), they are phased in according to adoption schedules that generally align with the diffusion
of similar equipment measures. For this analysis, we used the Council’s retrofit ramp rates, labeled “Retro”.
• Cu stomer adoption rates , also referred to as take rates or ramp rates, are applied to measures on a year by year basis. These rates represent customer adoption of measures when delivered through a
best-practice portfolio of well-operated efficiency programs under a reasonable policy or regulatory
framework. Information channels are assumed to be established and efficient for marketing, educating consumers, and coordinating with trade allies and delivery partners. The primary barrier to adoption
reflected in this case is customer preferences. Again, these are based on the ramp rates from the
Northwest Power and Conservation Council’s 2021 Plan.
The ramp rates referenced above were adapted for use for assessing natural gas measure potential. We
describe this process in Section 7. The customer adoption rates used in this study are available in Appendix B.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 167 of 794
3
MA RKET CHARACTERIZATION A ND MARKET PROFILES
In this section, we describe how customers in the Avista service territory use natural gas in the base year of the study, 2019. It begins with a high-level summary of energy use across all sectors and then delves
into each sector in more detail.
Overall Energy Use Summary
Total natural gas consumption for all sectors for Avista’s Washington territory in 2019 was 19,411,285
dekatherms. As shown in Figure 3-1 and Table 3-1, the residential sector accounts for the largest share of
annual energy use at 64%, followed by the commercial sector at 35%. The industrial sector accounts for 2% of usage.
Figure 3-1 Sector-Level Natural Gas Use in Base Year 2019, Washington (annual therms, percent)

Table 3-1 Avista Sector Control Totals, Washington, 2019
Sector Natural Gas
Use (dekatherms) % of Use
Residential 12,344,250 64%
Commercial 6,718,365 35%
Industrial 348,670 2%
Total 19,411,285 100%

Residential, 57%
Commercial, 41%
Industrial, 2%
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 168 of 794
Total natural gas consumption for all sectors for Avista’s Idaho territory in 2019 was 10,131,866 dekatherms.
As shown in Figure 3-2 and Table 3-2, the residential sector accounts for the largest share of annual energy
use at 57%, followed by the commercial sector at 41%. The industrial sector accounts for 2% of usage.
Figure 3-2 Sector-Level Natural Gas Use in Base Year 2019, Idaho (annual therms, percent)

Table 3-2 Avista Sector Control Totals, Idaho, 2019
Sector Natural Gas
Use (dekatherms) % of Use
Residential 5,782,934 57%
Commercial 4,110,228 41%
Industrial 238,705 2%
Total 10,131,866 100%

Residential, 57%
Commercial, 41%
Industrial, 2%
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 169 of 794
Residential Sector
Washington Characterization
The total number of households and gas sales for the service territory were obtained from Avista’s actual
sales for 2019. Details, including number of households and 2019 natural gas consumption for the
residential sector in Washington can be found in Table 3-3 below. In 2019, there were nearly 156,000 households in Avista’s Washington territory that used a total of 12,344,250 dekatherms, resulting in an
average use per household of 796 therms per year. This is an important number for the calibration process.
These values represent weather actuals for 2019 and were adjusted within LoadMAP to normal weather
using heating degree day, base 65°F, using data provided by Avista.
Table 3-3 Residential Sector Control Totals, Washington, 2019
Segment Households Natural Gas Use
(dekatherms)
Annual Use/Customer
(therms/HH)
Single Family 94,282 8,083,082 857
Multi-Family 8,684 469,031 540
Mobile Home 5,582 402,027 720
Low Income 46,521 3,390,109 729
Total 155,069 12,344,250 796
Figure 3-3 Residential Natural Gas Use by Segment, Washington, 2019

Figure 3-4 shows the distribution of annual natural gas consumption by end use for an average residential
household. Space heating comprises most of the load at 82% followed by water heating at 12%.
Appliances, Secondary Heating, and Miscellaneous loads make up the remaining portion (6%) of the total
load. This is expected for a natural gas profile as there are very few miscellaneous technologies. One example is natural gas barbecues.
Single Family
66%
Multi-Family
4%
Mobile Home
3%
Low Income
27%
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 170 of 794
Figure 3-4 Residential Natural Gas Use by End Use, Washington, 2019

Avista’s GenPOP survey informed estimates of the saturation of key equipment types, which were used to
distribute usage at the technology and end use level. However, because the vintage of the GenPOP survey
is 2013, trends from more recent surveys were applied where appropriate, while still maintaining the more
unique characteristics of Avista’s market.
Figure 3-4 presents average natural gas intensities by end use and housing type. Single family homes
consume substantially more energy in space heating. This is due to two factors. The first is that single family homes are larger. The second is that more walls are exposed to the outside environment, compared
to multifamily dwellings with many shared walls. This increases heat transfer, resulting in greater heating
loads. Water heating consumption is higher in single family homes as well. This is due to a greater number of occupants, which increases the demand for hot water.
Figure 3-5 Residential Energy Intensity by End Use and Segment, Washington, 2019 (Annual Therms/HH)

Space Heating
82%
Secondary Heating
2%
Water Heating
12%
Appliances
2%
Miscellaneous
2%
0
100
200
300
400
500
600
700
800
900
1,000
Single Family Multi-Family Mobile Home Low Income Average
Home
therms/
HH
Space Heating
Secondary Heating
Water Heating
Appliances
Miscellaneous
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 171 of 794
The market profile for an average home in the residential sector is presented in Table 3-4 below. An important step in the profile development process is model calibration. All consumption within an average
home must sum up to the intensity extracted from billing data. This is necessary so estimates of
consumption for a piece of equipment do not exceed the actual usage in a home.
Table 3-4 Average Market Profile for the Residential Sector, Washington, 2019
End Use Technology Saturation UEC
(therms)
Intensity
(therms/HH)
Usage
(dekatherms)
Space Heating Furnace - Direct Fuel 84.9% 747.2 634.6 9,840,233
Boiler - Direct Fuel 2.4% 674.2 16.2 251,417
Secondary Heating Fireplace 12.7% 137.3 17.4 269,840
Water Heating Water Heater <= 55 gal. 52.2% 177.8 92.9 1,440,263
Appliances Clothes Dryer 27.3% 18.0 4.9 76,440
Stove/Oven 58.9% 17.4 10.3 159,040
Miscellaneous Pool Heater 0.8% 80.1 0.6 9,491
Miscellaneous 100.0% 19.2 19.2 297,525
Total 796.0 12,344,250

Idaho Characterization
Details for the residential sector in Idaho can be found in Table 3-5 below. In 2019, there were 77,804
households in Avista’s Washington territory that used a total of 5,782,934 dekatherms, resulting in an
average use per household of 743 therms per year.
Table 3-5 Residential Sector Control Totals, Idaho, 2019
Segment Households Natural Gas Use
(dekatherms)
Annual Use/Customer
(therms/HH)
Single Family 47,305 3,780,793 799
Multi-Family 3,812 191,962 504
Mobile Home 3,501 235,056 671
Low Income 23,186 1,575,123 679
Total 77,804 5,782,934 743
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 172 of 794
Figure 3-6 Residential Natural Gas Use by Segment, Idaho, 2019

Figure 3-7 shows the distribution of annual natural gas consumption by end use for an average residential
household. Space heating comprises a majority of the load at 82% followed by water heating at 12%. Miscellaneous loads make up a very small portion of the total load, as expected.
Figure 3-7 Residential Natural Gas Use by End Use, Idaho, 2019

Avista’s 2013 GenPOP survey informed estimates of the saturation of key equipment types, which were
used to distribute usage at the technology and end use level.
Figure 3-8 presents average natural gas intensities by end use and housing type. Single family homes
consume substantially more energy in space heating. Water heating consumption is higher in single family homes as well, due to a greater number of occupants, which increases the demand for hot water.
Single Family
66%
Multi-Family
4%
Mobile Home
3%
Low Income
27%
Space Heating
82%
Secondary Heating
2%
Water Heating
12%
Appliances
2%
Miscellaneous
2%
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 173 of 794
Figure 3-8 Residential Energy Intensity by End Use and Segment, Idaho, 2019 (Annual Therms/HH)

The market profile for an average home in the residential sector is presented in Table 3-6 below. An
important step in the profile development process is model calibration. All consumption within an average
home must sum up to the intensity extracted from billing data. This is necessary so estimates of consumption for a piece of equipment do not exceed the actual usage in a home.
Table 3-6 Average Market Profile for the Residential Sector, 2019
End Use Technology Saturation UEC
(therms)
Intensity
(therms/HH)
Usage
(dekatherms)
Space Heating Furnace - Direct Fuel 81.0% 712.8 577.0 4,489,534
Boiler - Direct Fuel 2.2% 643.6 14.0 108,672
Secondary Heating Fireplace 16.9% 131.4 22.2 172,526
Water Heating Water Heater <= 55 gal. 54.6% 177.5 96.9 753,951
Appliances Clothes Dryer 14.7% 21.6 3.2 24,700
Stove/Oven 31.7% 20.8 6.6 51,415
Miscellaneous Pool Heater 0.3% 105.0 0.3 2,345
Miscellaneous 100.0% 23.1 23.1 179,792
Total 743.3 5,782,934

0
100
200
300
400
500
600
700
800
900
1,000
Single Family Multi-Family Mobile Home Low Income Average
Home
therms/
HH
Space Heating
Secondary Heating
Water Heating
Appliances
Miscellaneous
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 174 of 794
Commercial Sector
Washington Characterization
The total number of nonresidential accounts and natural gas sales for the Washington service territory
were obtained from Avista’s customer account database.
AEG first separated the Commercial accounts from Industrial by analyzing the SIC codes and rate codes
assigned in the company’s billing system. Prior to using the data, AEG inspected individual accounts to confirm proper assignment. This was done on the top accounts within each segment, but also via spot
checks when reviewing the database. Energy use from accounts where the customer type could not be
identified were distributed proportionally to all C&I segments.
Once the billing data was analyzed, the final segment control totals were derived by distributing the total 2019 nonresidential load to the sectors and segments according to the proportions in the billing data.
Table 3-7 below shows the final allocation of energy to each segment in the commercial sector, as well as the energy intensity on a square-foot basis. Intensities for each segment were derived from a combination
of the 2019 CBSA and equipment saturations extracted from Avista’s database. The CBSA intensities
corresponded to spaces with lower natural gas saturations than Avista’s database, so AEG increased
intensities proportionally based on the additional presence of natural gas-consuming equipment.
Table 3-7 Commercial Sector Control Totals, Washington, 2019
Segment Description
Intensity
(therms/Sq
Ft)
2019 Natural Gas
Use (dekatherms)
Office Traditional office-based businesses including finance,
insurance, law, government buildings, etc. 0.60 481,953
Restaurant Sit-down, fast food, coffee shop, food service, etc. 2.68 65,351
Retail Department stores, services, boutiques, strip malls etc. 0.83 837,065
Grocery Supermarkets, convenience stores, market, etc. 0.95 154,034
School Day care, pre-school, elementary, secondary schools 0.29 269,873
College College, university, trade schools, etc. 0.62 272,030
Health Health practitioner office, hospital, urgent care centers, etc. 1.04 315,668
Lodging Hotel, motel, bed and breakfast, etc. 0.68 172,829
Warehouse Large storage facility, refrigerated/unrefrigerated warehouse 0.68 358,315
Miscellaneous
Catchall for buildings not included in other segments,
includes churches, recreational facilities, public assembly,
correctional facilities, etc.
1.16 1,183,111
Total 0.75 4,110,228
Figure 3-9 shows each segments’ natural gas consumption as a percentage of the entire commercial sector
energy consumption. The three segments with the highest natural gas usage in 2019 are miscellaneous,
retail, and office, in descending order. As expected, the highest intensity segment is restaurant. This is
based on the high presence of food preparation equipment.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 175 of 794
Figure 3-9 Commercial Natural Gas Use by Segment, Washington, 2019

Figure 3-10 shows the distribution of natural gas consumption by end use for the entire commercial sector.
Space heating is the largest end use, followed closely by water heating. The miscellaneous end use is quite
small, as expected.
Figure 3-10 Commercial Sector Natural Gas Use by End Use, Washington, 2019

Figure 3-11 presents average natural gas intensities by end use and segment.
Office
13%
Restaurant
4%
Retail
16%
Grocery
4%
School
3%
College
3%
Health
9%
Lodging
4%
Warehouse
9%
Miscellaneous
35%
Space Heating
61%
Water Heating
25%
Food Preparation
9%
Miscellaneous
5%
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 176 of 794
Figure 3-11 Commercial Energy Usage Intensity by End Use and Segment, Washington, 2019 (Annual
Therms/Sq. Ft)

The total market profile for an average building in the commercial sector is presented in Table 3-8 below.
Avista customer account data informed the market profile by providing information on saturation of key
equipment types. Secondary data was used to develop estimates of energy intensity and square footage and to fill in saturations for any equipment types not included in the database.
Table 3-8 Average Market Profile for the Commercial Sector, Washington, 2019
End Use Technology Saturation
EUI
(therms/
Sq Ft)
Intensity
(therms/
Sq Ft)
Usage
(dekatherms)
Space Heating
Furnace 53.6% 0.44 0.23 1,898,166
Boiler 32.6% 0.79 0.26 2,086,967
Unit Heater 4.7% 0.27 0.01 100,644
Water Heating Water Heater 69.7% 0.30 0.21 1,681,122
Food Preparation
Oven 11.3% 0.06 0.01 53,746
Conveyor Oven 5.6% 0.10 0.01 45,982
Double Rack Oven 5.6% 0.15 0.01 69,855
Fryer 7.3% 0.34 0.03 202,977
Broiler 12.2% 0.07 0.01 70,869
Griddle 16.4% 0.05 0.01 70,017
Range 17.9% 0.06 0.01 82,852
Steamer 2.1% 0.06 0.00 9,251
Commercial Food Prep Other 0.2% 0.01 0.00 149
Miscellaneous Pool Heater 0.9% 0.01 0.00 1,034
Miscellaneous 100.0% 0.04 0.04 344,734
Total 0.83 6,718,365

- 0.20 0.40 0.60 0.80 1.00 1.20 1.40
Average Building
Miscellaneous
Warehouse
Lodging
Health
College
School
Grocery
Retail
Office
therms/Sq Ft
- 0.50 1.00 1.50 2.00 2.50 3.00
Restaurant
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 177 of 794
Idaho Characterization
The total number of nonresidential accounts and natural gas sales for the Idaho service territory were obtained from Avista’s customer account database.
Table 3-9 below shows the final allocation of energy to each segment in the commercial sector, as well as
the energy intensity on a square-foot basis. Intensities for each segment were derived from a combination
of the 2019 CBSA and equipment saturations extracted from Avista’s database. The CBSA intensities
corresponded to spaces with lower natural gas saturations than Avista’s database, so AEG increased
intensities proportionally based on the additional presence of natural gas-consuming equipment.
Table 3-9 Commercial Sector Control Totals, Idaho, 2019
Segment Description
Intensity
(therms/Sq
Ft)
2019 Natural Gas
Use (dekatherms)
Office Traditional office-based businesses including finance,
insurance, law, government buildings, etc. 0.60 481,953
Restaurant Sit-down, fast food, coffee shop, food service, etc. 2.68 65,351
Retail Department stores, services, boutiques, strip malls etc. 0.83 837,065
Grocery Supermarkets, convenience stores, market, etc. 0.95 154,034
School Day care, pre-school, elementary, secondary schools 0.29 269,873
College College, university, trade schools, etc. 0.62 272,030
Health Health practitioner office, hospital, urgent care centers, etc. 1.04 315,668
Lodging Hotel, motel, bed and breakfast, etc. 0.68 172,829
Warehouse Large storage facility, refrigerated/unrefrigerated warehouse 0.68 358,315
Miscellaneous
Catchall for buildings not included in other segments,
includes churches, recreational facilities, public assembly,
correctional facilities, etc.
1.16 1,183,111
Total 0.75 4,110,228
Figure 3-12 shows each segments’ natural gas consumption as a percentage of the entire commercial
sector energy consumption. The four segments with the highest natural gas usage in 2019 are
miscellaneous, retail, office, and warehouse, in descending order. As expected, the highest intensity segment is restaurant. This is based on the high presence of food preparation equipment.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 178 of 794
Figure 3-12 Commercial Natural Gas Use by Segment, Idaho, 2019

Figure 3-13 shows the distribution of natural gas consumption by end use for the entire commercial sector.
Space heating is the largest end use, followed closely by water heating and food preparation. The
miscellaneous end use is quite small, as expected.
Figure 3-13 Commercial Sector Natural Gas Use by End Use, Idaho, 2019

Figure 3-14 presents average natural gas intensities by end use and segment.
Office
13%
Restaurant
4%
Retail
16%
Grocery
4%School
3%
College
3%Health
9%
Lodging
4%
Warehouse
9%
Miscellaneous
35%
Space Heating
61%
Water Heating
25%
Food Preparation
9%
Miscellaneous
5%
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 179 of 794
Figure 3-14 Commercial Energy Usage Intensity by End Use and Segment, Idaho, 2019 (Annual
Therms/Sq. Ft)

The total market profile for an average building in the commercial sector is presented in Table 3-10 below.
Avista customer account data informed the market profile by providing information on saturation of key
equipment types. Secondary data was used to develop estimates of energy intensity and square footage and to fill in saturations for any equipment types not included in the database.
Table 3-10 Average Market Profile for the Commercial Sector, Idaho, 2019
End Use Technology Saturati
on
EUI
(therms/ Sq
Ft)
Intensity
(therms/
Sq Ft)
Usage
(dekatherms)
Space Heating
Furnace 50.7% 0.43 0.22 1,183,907
Boiler 35.7% 0.66 0.24 1,286,757
Unit Heater 4.9% 0.25 0.01 67,294
Water Heating Water Heater 69.3% 0.27 0.19 1,025,922
Food Preparation
Oven 9.9% 0.07 0.01 37,863
Conveyor Oven 4.9% 0.12 0.01 32,393
Double Rack Oven 4.9% 0.18 0.01 49,212
Fryer 7.2% 0.32 0.02 125,738
Broiler 11.3% 0.05 0.01 29,409
Griddle 15.7% 0.04 0.01 32,103
Range 17.5% 0.04 0.01 39,839
Steamer 3.1% 0.04 0.00 5,935
Commercial Food Prep Other 0.3% 0.01 0.00 141
Miscellaneous Pool Heater 0.8% 0.01 0.00 563
Miscellaneous 100.0% 0.04 0.04 193,152
Total 0.75 4,110,228

- 0.20 0.40 0.60 0.80 1.00 1.20 1.40
Average Building
Miscellaneous
Warehouse
Lodging
Health
College
School
Grocery
Retail
Office
therms/Sq Ft
- 0.50 1.00 1.50 2.00 2.50 3.00
Restaurant
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 180 of 794
Industrial Sector
Washington Characterization
The total sum of natural gas used in 2019 by Avista’s Washington industrial customers was 348,670
dekatherms. Like in the commercial sector, customer account data was used to allocate usage among
segments. Energy intensity was derived from AEG’s Energy Market Profiles database. Most industrial measures are installed through custom programs, where the unit of measure is not as necessary to estimate potential.
Table 3-11 Industrial Sector Control Totals, Washington, 2019
Segment Intensity (therms/employee) Natural Gas Usage
(dekatherms)
Washington Industrial 1,716 348,670
Figure 3-15 shows the distribution of annual natural gas consumption by end use for all industrial
customers. Two major sources were used to develop this consumption profile. The first was AEG’s analysis
of warehouse usage as part of the commercial sector. We begin with this prototype as a starting point to represent non-process loads. We then added in process loads using our Energy Market Profiles database,
which summarizes usage by end use and process type. Accordingly, process is the largest overall end use
for the industrial sector, accounting for 87% of energy use. Heating is the second largest end use, and miscellaneous, non-process industrial uses round out consumption.
Figure 3-15 Industrial Natural Gas Use by End Use, Washington, 2019

Table 3-12 shows the composite market profile for the industrial sector. Process cooling is very small and represents niche technologies such as gas-driven absorption chillers.
Space Heating
6%
Process
87%
Miscellaneous
7%
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 181 of 794
Table 3-12 Average Natural Gas Market Profile for the Industrial Sector, Washington, 2019
End Use Technology Saturation
EUI
(therms/
sq ft)
Intensity
(therms/
Sq ft)
Usage
(dekatherms)
Space Heating
Furnace 27.5% 107.88 29.64 6,024
Boiler 58.8% 107.88 63.42 12,890
Unit Heater 13.7% 107.88 14.82 3,012
Process
Process Boiler 100.0% 758.47 758.47 154,154
Process Heating 100.0% 675.00 675.00 137,190
Process Cooling 100.0% 7.83 7.83 1,592
Other Process 100.0% 50.93 50.93 10,350
Miscellaneous Miscellaneous 100.0% 115.41 115.41 23,457
Total 1,715.53 348,670
Idaho Characterization
The total sum of natural gas used in 2019 by Avista’s Idaho industrial customers was 238,705 dekatherms.
Energy use intensity is slightly higher than Washington at 2,008 therms/sq ft.
Table 3-13 Industrial Sector Control Totals, Idaho, 2019
Segment Intensity (therms/employee) Natural Gas Usage
(dekatherms)
Idaho Industrial 2,008 238,705
Figure 3-16 shows the distribution of annual natural gas consumption by end use for all industrial customers. Two major sources were used to develop this consumption profile. The first was AEG’s analysis
of warehouse usage as part of the commercial sector. We begin with this prototype as a starting point to
represent non-process loads. We then added in process loads using our Energy Market Profiles database, which summarizes usage by end use and process type. Accordingly, process is the largest overall end use
for the industrial sector, accounting for 87% of energy use. Heating is the second largest end use, and
miscellaneous, non-process industrial uses round out consumption.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 182 of 794
Figure 3-16 Industrial Natural Gas Use by End Use, Idaho, 2019

Table 3-14 shows the composite market profile for the industrial sector. Process cooling is very small and
represents technologies such as gas-driven absorption chillers.
Table 3-14 Average Natural Gas Market Profile for the Industrial Sector, Idaho, 2019
End Use Technology Saturation
EUI
(therms/
sq ft)
Intensity
(therms/
Sq ft)
Usage
(dekatherms)
Space Heating
Furnace 27.5% 126.29 34.70 4,124
Boiler 58.8% 126.29 74.24 8,824
Unit Heater 13.7% 126.29 17.35 2,062
Process
Process Boiler 100.0% 887.92 887.92 105,537
Process Heating 100.0% 790.21 790.21 93,922
Process Cooling 100.0% 9.17 9.17 1,090
Other Process 100.0% 59.62 59.62 7,086
Miscellaneous Miscellaneous 100.0% 135.11 135.11 16,059
Total 2,008.33 238,705

Space Heating
6%
Process
87%
Miscellaneous
7%
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 183 of 794
4
BASELINE PROJECTION
Prior to developing estimates of energy conservation potential, we developed a baseline end-use projection to quantify what the consumption is likely to be in the future in absence of any energy
conservation programs. The savings from past programs are embedded in the forecast, but the baseline
projection assumes that those past programs cease to exist in the future. Thus, the potential analysis
captures all possible savings from future programs.
The baseline projection incorporates assumptions about:
• 2019 energy consumption based on the market profiles
• Customer population growth
• Appliance/equipment standards and building codes already mandated
• Appliance/equipment purchase decisions
• Avista’s customer forecast
Trends in fuel shares and appliance saturations and assumptions about miscellaneous natural gas growth
Although it aligns closely, the baseline projection is not Avista’s official load forecast. Rather it was
developed as an integral component of our modeling construct to serve as the metric against which
energy conservation potentials are measured. This chapter presents the baseline projections we developed
for this study. Below, we present the baseline projections for each sector, which include projections of
annual use in dekatherms. We also present a summary across all sectors.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 184 of 794
Overall Baseline Projection
Washington Projection
Table 4-1 and Figure 4-1 provide a summary of the baseline projection for annual use by sector for the
Avista’s Washington service territory. Overall, the forecast shows modest growth in natural gas consumption, driven by the residential and commercial sectors
Table 4-1 Baseline Projection Summary by Sector, Washington, Selected Years (dekatherms)
Sector 2019 2021 2023 2030 2040 % Change
('19-'40)
Avg.
Growth
Residential 12,344,250 12,180,267 12,523,563 13,568,829 14,418,227 16.8% 0.7%
Commercial 6,718,365 6,596,157 6,622,904 6,725,824 6,909,984 2.9% 0.1%
Industrial 348,670 341,870 336,318 317,863 291,665 -16.3% -0.9%
Total 19,411,285 19,118,293 19,482,785 20,612,516 21,619,876 11.4% 0.5%
Figure 4-1 Baseline Projection Summary by Sector, Washington (dekatherms)

-
5,000,000
10,000,000
15,000,000
20,000,000
25,000,000
2019 2022 2025 2028 2031 2034 2037 2040
Dth
Residential Commercial Industrial Avista Forecast
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 185 of 794
Idaho Projection
Table 4-2 and Figure 4-2 provide a summary of the baseline projection for annual use by sector for Avista’s
Idaho service territory. Overall, the forecast shows modest growth in natural gas consumption, driven roughly equally by the residential sector.
Table 4-2 Baseline Projection Summary by Sector, Idaho, Selected Years (dekatherms)
Sector 2019 2021 2023 2030 2040 % Change
('19-'40)
Avg.
Growth
Residential 5,782,934 5,757,753 5,989,779 6,677,657 7,614,162 31.7% 1.3%
Commercial 4,110,228 4,027,575 4,071,925 4,112,209 4,199,550 2.2% 0.1%
Industrial 238,705 234,049 229,897 214,701 193,107 -19.1% -1.0%
Total 10,131,866 10,019,377 10,291,600 11,004,568 12,006,819 18.5% 0.8%
Figure 4-2 Baseline Projection Summary by Sector, Idaho (dekatherms)

-
5,000,000
10,000,000
15,000,000
20,000,000
25,000,000
2019 2022 2025 2028 2031 2034 2037 2040
Dth
Residential Commercial Industrial Avista Forecast
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 186 of 794
Residential Sector
Washington Projection
Table 4-3 and
Figure 4-3 present the baseline projection for natural gas at the end-use level for the residential sector,
as a whole. Overall, residential use increases from 12,344,250 dekatherms in 2019 to 14,418,227 dekatherms
in 2040, an increase of 16.8%. Factors affecting growth include a moderate increase in number of households and customers, and a decrease in equipment consumption due to future standards and naturally occurring efficiency improvements (notably the AFUE upcoming 92% furnace standard).
We model gas-fired fireplaces as secondary heating. These consume energy and may heat a space but
are rarely relied on to be a primary heating technology. As such, they are estimated to be more aesthetic
and less weather-dependent. This end use grows faster than others since new homes are more likely to
install a unit, increasing fireplace stock. Miscellaneous is a very small end use including technologies with low penetration, such as gas barbeques.
Table 4-3 Residential Baseline Projection by End Use, Washington (dekatherms)
End Use 2019 2021 2023 2030 2040
%
Change
('19-'40)
Avg.
Growth
Space Heating 10,091,649 9,884,547 10,148,613 10,898,317 11,377,205 12.7% 0.6%
Secondary Heating 269,840 268,460 275,328 300,411 328,634 21.8% 0.9%
Water Heating 1,440,263 1,475,763 1,532,049 1,743,214 2,015,278 39.9% 1.6%
Appliances 235,480 240,292 248,325 278,255 315,399 33.9% 1.4%
Miscellaneous 307,017 311,205 319,248 348,632 381,710 24.3% 1.0%
Total 12,344,250 12,180,267 12,523,563 13,568,829 14,418,227 16.8% 0.7%

Figure 4-3 Residential Baseline Projection by End Use, Washington (dekatherms)

-
2,000,000
4,000,000
6,000,000
8,000,000
10,000,000
12,000,000
14,000,000
16,000,000
2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041
Dth
Space Heating
Secondary
Heating
Water Heating
Appliances
Miscellaneous
Avista Forecast
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 187 of 794
Idaho Projection
Table 4-4 and Figure 4-4 present the baseline projection for natural gas at the end-use level for the
residential sector, as a whole. Overall, residential use increases from 5,782,934 dekatherms in 2019 to 7,614,162 dekatherms in 2040, an increase of 31.7%.
Table 4-4 Residential Baseline Projection by End Use, Idaho (dekatherms)
End Use 2019 2021 2023 2030 2040 % Change
('19-'40)
Avg.
Growth
Space Heating 4,598,206 4,543,217 4,723,227 5,238,352 5,912,290 28.6% 1.2%
Secondary Heating 172,526 172,767 178,636 197,303 224,372 30.1% 1.3%
Water Heating 753,951 777,712 814,170 936,965 1,126,311 49.4% 1.9%
Appliances 76,115 78,239 81,587 92,714 109,623 44.0% 1.7%
Miscellaneous 182,137 185,819 192,158 212,322 241,565 32.6% 1.3%
Total 5,782,934 5,757,753 5,989,779 6,677,657 7,614,162 31.7% 1.3%
Figure 4-4 Residential Baseline Projection by End Use, Idaho (dekatherms)

-
2,000,000
4,000,000
6,000,000
8,000,000
10,000,000
12,000,000
14,000,000
16,000,000
2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041
Dth
Space Heating
Secondary
Heating
Water Heating
Appliances
Miscellaneous
Avista Forecast
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 188 of 794
Commercial Sector
Washington Projection
Annual natural gas use in the commercial sector grows 24.7% during the overall forecast horizon, starting
at 6,197,173 dekatherms in 2019, and increasing to 6,909,984 dekatherms in 2040. Table 4-5 and Figure
4-5 present the baseline projection at the end-use level for the commercial sector, as a whole. Similar to
the residential sector, market size is increasing and usage per square foot is decreasing slightly.
Table 4-5 Commercial Baseline Projection by End Use, Washington (dekatherms)
End Use 2019 2021 2023 2030 2040
%
Change
('19-'40)
Avg.
Growth
Space Heating 4,085,777 3,956,080 3,975,113 4,039,997 4,138,972 1.3% 0.1%
Water Heating 1,681,122 1,679,620 1,678,355 1,686,750 1,736,171 3.3% 0.2%
Food Preparation 605,698 611,422 617,138 636,007 658,775 8.8% 0.4%
Miscellaneous 345,768 349,035 352,298 363,069 376,067 8.8% 0.4%
Total 6,718,365 6,596,157 6,622,904 6,725,824 6,909,984 2.9% 0.1%
Figure 4-5 Commercial Baseline Projection by End Use, Washington (dekatherms)

-
1,000,000
2,000,000
3,000,000
4,000,000
5,000,000
6,000,000
7,000,000
8,000,000
2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041
Dth
Space Heating
Water Heating
Food Preparation
Miscellaneous
Avista Forecast
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 189 of 794
Idaho Projection
Annual natural gas use in the Idaho commercial sector grows 2.2% during the overall forecast horizon,
starting at 4,110,228 dekatherms in 2019, and increasing to 4,199,550 dekatherms in 2040. Table 4-6 and
Figure 4-6 present the baseline projection at the end-use level for the commercial sector, as a whole.
Similar to the residential sector, market size is increasing and usage per square foot is decreasing slightly.
Table 4-6 Commercial Baseline Projection by End Use, Idaho (dekatherms)
End Use 2019 2021 2023 2030 2040
%
Change
('19-'40)
Avg.
Growth
Space Heating 2,537,957 2,453,619 2,482,525 2,509,340 2,555,560 0.7% 0.0%
Water Heating 1,025,922 1,023,306 1,029,755 1,029,131 1,052,936 2.6% 0.1%
Food Preparation 352,633 355,410 361,216 370,312 381,488 8.2% 0.4%
Miscellaneous 193,715 195,240 198,430 203,426 209,566 8.2% 0.4%
Total 4,110,228 4,027,575 4,071,925 4,112,209 4,199,550 2.2% 0.1%
Figure 4-6 Commercial Baseline Projection by End Use, Idaho (dekatherms)

-
1,000,000
2,000,000
3,000,000
4,000,000
5,000,000
6,000,000
7,000,000
8,000,000
2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041
Dth
Space Heating
Water Heating
Food Preparation
Miscellaneous
Avista Forecast
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 190 of 794
Industrial Sector
Washington Projection
Industrial sector usage increases throughout the planning horizon. Table 4-7 and Figure 4-7 present the
projection at the end-use level. Overall, industrial annual natural gas use decreases from 348,670
dekatherms in 2019 to 291,665 dekatherms in 2040. Growth is consistently around -0.9% per year.
Table 4-7 Industrial Baseline Projection by End Use, Washington (dekatherms)
End Use 2019 2021 2023 2030 2040 % Change
('19-'40)
Avg.
Growth
Space Heating 21,926 20,665 20,227 18,789 16,903 -22.9% -1.2%
Process 303,287 298,146 293,399 277,603 255,037 -15.9% -0.8%
Miscellaneous 23,457 23,059 22,692 21,470 19,725 -15.9% -0.8%
Total 348,670 341,870 336,318 317,863 291,665 -16.3% -0.9%
Figure 4-7 Industrial Baseline Projection by End Use, Washington (dekatherms)

-
50,000
100,000
150,000
200,000
250,000
300,000
2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041
Dth
Space Heating
Process
Miscellaneous
Avista Forecast
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 191 of 794
Idaho Projection
Industrial sector usage increases throughout the planning horizon. Table 4-8 and Figure 4-8 present the
projection at the end-use level. Overall, industrial annual natural gas use descreases from 238,705
dekatherms in 2019 to 193,107 dekatherms in 2040.
Table 4-8 Industrial Baseline Projection by End Use, Idaho (dekatherms)
End Use 2019 2021 2023 2030 2040
%
Change
('19-'40)
Avg.
Growth
Heating 15,011 14,147 13,829 12,713 11,232 -25.2% -1.4%
Process 207,635 204,115 200,556 187,488 168,818 -18.7% -1.0%
Miscellaneous 16,059 15,787 15,511 14,501 13,057 -18.7% -1.0%
Total 238,705 234,049 229,897 214,701 193,107 -19.1% -1.0%
Figure 4-8 Industrial Baseline Projection by End Use, Idaho (dekatherms)

-
50,000
100,000
150,000
200,000
250,000
300,000
2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041
Dth
Space Heating
Process
Miscellaneous
Avista Forecast
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 192 of 794
5
OVERALL ENERGY EFFICIENCY POTENTIAL
This chapter presents the measure-level energy conservation potential across all sectors for Avista’s Washington and Idaho territories. This includes every possible measure that is considered in the measure
list, regardless of program implementation concerns. Year-by-year savings for annual energy usage are
available in the LoadMAP model and measure assumption summary, which were provided to Avista at the
conclusion of the study. Please note that all savings are provided at the customer site. This section includes potential from the residential, commercial, and industrial analyses.
Overall Ene rgy Efficiency Potential
Washington Potential
Table 5-1 and Figure 5-1 summarize the energy conservation savings in terms of annual energy use for all
measures for four levels of potential relative to the baseline projection. Figure 5-2 displays the energy
conservation forecasts. Savings are represented in cumulative terms, which reflect the effects of persistent
savings in prior years in addition to new savings. This allows for the reporting of annual savings impacts as they actually impact each year of the forecast.
• Te chnical Potential reflects the adoption of all conservation measures regardless of cost-
effectiveness. In this potential case, efficient equipment makes up all lost opportunity installations and
all retrofit measures are installed, regardless of achievability. 2021 first-year savings are 421,965
dekatherms, or 2.2% of the baseline projection. Cumulative savings in 2030 are 5,084,999 dekatherms,
or 24.7% of the baseline. By 2040, cumulative savings reach 8,908,493 dekatherms, or 41.2% of the
baseline. Technical potential is useful as a theoretical construct, applying an upper bound to the potential that may be realized in any one year. Other levels of potential are based off this level which makes it an important component in the estimation of potential.
• Ac h ievable Technical Po tential refines technical potential by applying customer participation
rates that account for market barriers, customer awareness and attitudes, program maturity, and other
factors that affect market penetration of conservation measures. For Avista’s gas CPA, ramp rates from
the 2021 Power Plan were customized for use in natural gas programs and applied. Since the 2021
Plan does not assign ramp rates for the majority of natural gas measures, we assigned these based
on similar electric technologies present in the Plan as a starting point. These ramp rates may be found
in Appendix B. 2021 first-year net savings are 187,983 dekatherms, or 1.0% of the baseline projection.
Cumulative net savings in 2030 are 3,183,398 dekatherms, or 15.4% of the baseline. By 2040 cumulative
savings reach 6,309,826 dekatherms, or 29.2% of the baseline.
• U CT Achievable E conomic Potential further refines achievable technical potential by applying
an economic cost-effectiveness screen. In this analysis, the cost-effectiveness is measured by the utility
cost test (UCT), which compares lifetime energy benefits to the total utility costs of delivering the
measure through a utility program, excluding monetized non-energy impacts. Avoided costs of energy
were provided by Avista. 2021 first-year savings are 75,820 dekatherms, or 0.4% of the baseline projection. Cumulative savings in 2030 are 1,386,479 dekatherms, or 6.7% of the baseline. By 2040 cumulative savings reach 3,560,512 dekatherms, or 16.5% of the baseline.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 193 of 794
• T R C Achievable Economic Potential further refines achievable technical potential by applying an economic cost-effectiveness screen. In this analysis, the cost-effectiveness is measured by the total
resource cost (TRC) test, which compares lifetime energy benefits to the total customer and utility
costs of delivering the measure through a utility program, including monetized non-energy impacts. AEG also applied benefits for non-gas energy savings, such as electric HVAC savings for
weatherization and lighting savings for retrocommissioning. We also applied the Council’s calibration
credit to space heating savings to reflect the fact that additional fuels may be used as a supplemental
heat source within an average home and may be accounted for within the TRC. Avoided costs of
energy were provided by Avista. A 10% conservation credit was applied to these costs per the Council
methodologies. 2021 first-year savings are 41,871 dekatherms, or 0.2% of the baseline projection.
Cumulative net savings in 2030 are 708,778 dekatherms, or 3.4% of the baseline. By 2040 cumulative
savings reach 2,319,723 dekatherms, or 10.7% of the baseline. Potential under the TRC test is lower
than UCT due to the inclusion of full measure costs rather than the utility portion. For most measures,
these far outweigh the quantified and monetized non-energy impacts included in the TRC.
Table 5-1 Summary of Energy Efficiency Potential, Washington (dekatherms)
Scenario 2021 2022 2025 2030 2040
Baseline Projection (Dth) 19,118,293 19,289,575 19,805,020 20,612,516 21,619,876
Cumulative Savings (Dth)
UCT Achievable Economic Potential 75,820 173,838 457,423 1,386,479 3,560,512
TRC Achievable Economic Potential 41,871 100,872 227,922 708,778 2,319,723
Achievable Technical Potential 187,983 416,584 1,221,810 3,183,398 6,309,826
Technical Potential 429,965 897,098 2,314,334 5,084,999 8,908,493
Cumulative Savings (% of Baseline)
UCT Achievable Economic Potential 0.4% 0.9% 2.3% 6.7% 16.5%
TRC Achievable Economic Potential 0.2% 0.5% 1.2% 3.4% 10.7%
Achievable Technical Potential 1.0% 2.2% 6.2% 15.4% 29.2%
Technical Potential 2.2% 4.7% 11.7% 24.7% 41.2%

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 194 of 794
Figure 5-1 Summary of Energy Efficiency Potential as % of Baseline Projection, Washington (dekatherms)

Figure 5-2 Baseline Projection and Energy Efficiency Forecasts, Washington (dekatherms)

Figure 5-3 shows the cumulative UCT achievable potential by sector for the full timeframe of the analysis
as percent of total. Table 5-2 summarizes UCT achievable potential by market sector for selected years.
While the residential and commercial sectors represent the lion’s share of the overall potential in the early
years, by the late-2020s, the residential sector share grows to a significant majority of savings potential.
Since industrial consumption is such a low percentage of the baseline once ineligible customers have been
excluded, potential for this sector makes up a lower percentage of the total. While residential and
commercial potential ramps up, industrial potential is mainly retrofit in nature, and is much flatter. This is
because process equipment is highly custom and most potential comes from controls modifications or
process adjustments rather than high-efficiency equipment upgrades. Additionally, we model
retrocommissioning to phase in evenly over the next twenty years. This measure has a maintenance
0
1,000,000
2,000,000
3,000,000
4,000,000
5,000,000
6,000,000
2021 2022 2025 2030 2040
Dth
UCT Achievable Economic TRC Achievable Economic Achievable Technical Technical
-
2,000,000
4,000,000
6,000,000
8,000,000
10,000,000
12,000,000
14,000,000
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041
Dth
Baseline Forecast
Achievable Economic TRC Potential
Achievable Economic UCT Potential
Achievable Technical Potential
Technical Potential
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 195 of 794
component, and not all existing facilities may be old enough to require the tune-up immediately but will be eligible at some point over the course of the study.
There is a notable downtick in residential savings around 2024. This is due to the impacts of the residential
forced-air furnace standard, which raises the baseline from AFUE 80% to AFUE 92%, which is a substantial
increase when the efficient option is an AFUE 95% unit.
Figure 5-3 Cumulative UCT Achievable Economic Potential by Sector, Washington (% of Total)

Table 5-2 Cumulative UCT Achievable Economic Potential by Sector, Washington, Selected Years (dekatherms)
Sector 2021 2022 2025 2030 2040
Residential 45,545 102,725 208,449 725,000 2,294,322
Commercial 28,070 66,690 237,773 642,051 1,241,314
Industrial 2,206 4,424 11,200 19,428 24,876
Total 75,820 173,838 457,423 1,386,479 3,560,512

0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
2022 2026 2030 2034 2038 2042
Share off
Total
Savings
Residential Commercial Industrial
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 196 of 794
Idaho Potential
Table 5-3 and Figure 5-4 summarize the energy conservation savings in terms of annual energy use for
all measures for four levels of potential relative to the baseline projection. Figure 5-5 displays the energy
conservation forecasts. Savings are represented in cumulative terms, which reflect the effects of persistent
savings in prior years in addition to new savings. This allows for the reporting of annual savings impacts as they actually impact each year of the forecast.
• Te chnical Pote ntial first-year savings in 2021 are 232,772 dekatherms, or 2.3% of the baseline
projection. Cumulative savings in 2030 are 2,777,509 dekatherms, or 25.2% of the baseline. By 2040,
cumulative savings reach 5,013,697 dekatherms, or 41.8% of the baseline.
• Ac h ievable Technical Po tential first-year net savings are 102,031 dekatherms, or 1.0% of the
baseline projection. Cumulative net savings in 2030 are 1,722,830 dekatherms, or 15.7% of the baseline. By 2040 cumulative savings reach 3,544,048 dekatherms, or 29.5% of the baseline.
• U CT Ac hievable E conomic Potential first-year savings are 35,816 dekatherms, or 0.4% of the
baseline projection. Cumulative savings in 2030 are 737,710 dekatherms, or 6.7% of the baseline. By
2040 cumulative savings reach 2,025,410 dekatherms, or 16.9% of the baseline.
• T R C Ac hievable E conomic Potential first-year savings are 26,220 dekatherms, or 0.3% of the
baseline projection. Cumulative net savings in 2030 are 417,020 dekatherms, or 3.8% of the baseline.
By 2040 cumulative savings reach 868,456 dekatherms, or 7.2% of the baseline. Potential under the
TRC test is lower than UCT due to the inclusion of full measure costs rather than the utility portion.
For most measures, these far outweigh the quantified and monetized non-energy impacts included
in the TRC.
Table 5-3 Summary of Energy Efficiency Potential, Idaho (dekatherms)
Scenario 2021 2022 2025 2030 2040
Baseline Projection (Dth) 10,019,377 10,144,894 10,520,169 11,004,568 12,006,819
Cumulative Savings (Dth)
UCT Achievable Economic Potential 35,816 87,995 229,283 737,710 2,025,410
TRC Achievable Economic Potential 26,220 62,285 136,883 417,028 868,456
Achievable Technical Potential 102,031 226,613 657,997 1,722,830 3,544,048
Technical Potential 232,772 490,826 1,273,202 2,777,509 5,013,697
Cumulative Savings (% of Baseline)
UCT Achievable Economic Potential 0.4% 0.9% 2.2% 6.7% 16.9%
TRC Achievable Economic Potential 0.3% 0.6% 1.3% 3.8% 7.2%
Achievable Technical Potential 1.0% 2.2% 6.3% 15.7% 29.5%
Technical Potential 2.3% 4.8% 12.1% 25.2% 41.8%

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 197 of 794
Figure 5-4 Summary of Energy Efficiency Potential as % of Baseline Projection, Idaho (dekatherms)

Figure 5-5 Summary of Energy Efficiency Potential as % of Baseline Projection, Idaho (dekatherms)

Figure 5-6 shows the cumulative UCT achievable potential by sector for the full timeframe of the analysis
as percent of total. Table 5-4 summarizes UCT achievable potential by market sector for selected years.
.
0
1,000,000
2,000,000
3,000,000
4,000,000
5,000,000
6,000,000
2021 2022 2025 2030 2040
Dth
UCT Achievable Economic TRC Achievable Economic Achievable Technical Technical
-
2,000,000
4,000,000
6,000,000
8,000,000
10,000,000
12,000,000
14,000,000
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041
Dth
Baseline Forecast
Achievable Economic TRC Potential
Achievable Economic UCT Potential
Achievable Technical Potential
Technical Potential
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 198 of 794
Figure 5-6 Cumulative UCT Achievable Economic Potential by Sector, Idaho (% of Total)

Table 5-4 Cumulative UCT Achievable Economic Potential by Sector, Idaho, Selected Years
(dekatherms)
Sector 2021 2022 2025 2030 2040
Residential 17,529 44,289 77,379 339,502 1,256,282
Commercial 16,775 40,676 144,201 384,730 751,926
Industrial 1,512 3,030 7,703 13,477 17,202
Total 35,816 87,995 229,283 737,710 2,025,410

0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
2022 2026 2030 2034 2038 2042
Share off
Total
Savings
Residential Commercial Industrial
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 199 of 794
6
SECTOR-LEVEL ENERGY EFFICIENCY POTENTIAL
The previous section provided a summary of potential for the Avista territory at the state level. In this
section, we provide details for each sector.
Residential Sector
Washington Potential
Table 6-1 and Figure 6-1 summarize the energy efficiency potential for the residential sector. In 2021, UCT
achievable economic potential is 45,545 dekatherms, or 0.4% of the baseline projection. By 2040, cumulative savings are 2,294,322 dekatherms, or 15.9% of the baseline.
Table 6-1 Residential Energy Conservation Potential Summary, Washington (dekatherms)
Scenario 2021 2022 2025 2030 2040
Baseline Forecast (Dth) 12,180,267 12,342,203 12,822,709 13,568,829 14,418,227
Cumulative Savings (Dth)
UCT Achievable Economic Potential 45,545 102,725 208,449 725,000 2,294,322
TRC Achievable Economic Potential 22,729 53,315 48,069 211,706 1,312,883
Achievable Technical Potential 137,500 304,182 858,976 2,272,407 4,576,510
Technical Potential 292,972 616,103 1,560,420 3,510,309 6,413,126
Energy Savings (% of Baseline)
UCT Achievable Economic Potential 0.4% 0.8% 1.6% 5.3% 15.9%
TRC Achievable Economic Potential 0.2% 0.4% 0.4% 1.6% 9.1%
Achievable Technical Potential 1.1% 2.5% 6.7% 16.7% 31.7%
Technical Potential 2.4% 5.0% 12.2% 25.9% 44.5%
Figure 6-1 Residential Energy Conservation by Case, Washington (dekatherms)

0
500,000
1,000,000
1,500,000
2,000,000
2,500,000
3,000,000
3,500,000
4,000,000
2021 2022 2025 2030 2040
Dth
UCT Achievable Economic TRC Achievable Economic Achievable Technical Technical
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 200 of 794
Figure 6-2 presents forecasts of energy savings by end use as a percent of total annual savings and
cumulative savings. Space heating makes up a majority of potential but declines slightly in the early to mid-2020s due to the future furnace standard.
Figure 6-2 Residential UCT Achievable Economic Potential – Cumulative Savings by End Use, Washington (dekatherms, % of total)

-
200,000
400,000
600,000
800,000
1,000,000
1,200,000
1,400,000
1,600,000
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039
Dth
Space Heating
Secondary Heating
Water Heating
Appliances
Miscellaneous
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039
Share of
Savings
Space Heating
Secondary Heating
Water Heating
Appliances
Miscellaneous
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 201 of 794
Table 6-2 identifies the top 20 residential measures by cumulative 2021 and 2022 savings. Furnaces,
learning thermostats, insulation and water heating are the top measures.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 202 of 794
Table 6-2 Residential Top Measures in 2021 and 2022, UCT Achievable Economic Potential,
Washington (dekatherms)
Rank Measure / Technology
2021 Cumulative
Potential Savings
(dekatherms)
% of
Total
2022 Cumulative
Potential Savings
(dekatherms)
% of
Total
1 Furnace - AFUE 92% 21,548 47% 50,231 49%
2 Gas Furnace - Maintenance - Restored
to nameplate 80% AFUE
13,118 29% 26,107 25%
3 ENERGY STAR Connected Thermostat -
Interactive/learning thermostat (ie,
NEST)
4,435 10% 9,925 10%
4 Insulation - Ceiling, Installation - R-38
(Retro only)
3,611 8% 8,000 8%
5 Water Heater - Instantaneous - ENERGY
STAR (UEF 0.87)
1,901 4% 5,973 6%
6 Insulation - Wall Cavity, Installation - R-
11
333 1% 741 1%
7 Gas Boiler - Steam Trap Maintenance -
Cleaned and restored
202 0% 399 0%
8 Building Shell - Whole-Home Aerosol
Sealing - 20% reduction in ACH50
163 0% 492 0%
9 Water Heater - Low Flow Showerhead
(1.5 GPM) - 1.5 GPM showerhead
75 0% 194 0%
10 Boiler - AFUE 85% 51 0% 130 0%
11 Water Heater - Faucet Aerators - 1.5
GPM faucet
51 0% 131 0%
12 ENERGY STAR Homes - Built Green spec
(NC Only)
47 0% 265 0%
13 Water Heater - Pipe Insulation -
Insulated 5' of pipe between unit and
conditioned space
10 0% 25 0%
14 Insulation - Slab Foundation - R-11 (NC
Only)
0 0% 23 0%
15 Building Shell - Liquid-Applied Weather-
Resistive Barrier - Spray-on weather
barrier applied
0 0% 0 0%
16 Clothes Dryer - NEEA/ENERGY STAR (CE
>60%)
0 0% 0 0%
17 Combined Boiler + DHW System
(Storage Tank) - Combined tankless
boiler unit for space and DHW
0 0% 0 0%
18 Combined Boiler + DHW System
(Tankless) - Combined tankless boiler
unit for space and DHW
0 0% 0 0%
19 Doors - Storm and Thermal - R-5 door 0 0% 0 0%
20 Ducting - Repair and Sealing - 50%
reduction in duct leakage
0 0% 0 0%
Subtotal 45,545 100% 102,636 100%
Total Savings in Year 45,545 100% 102,725 100%
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 203 of 794
Idaho Potential
Table 6-3 and Figure 6-3 summarize the energy efficiency potential for the residential sector. In 2021, UCT
achievable economic potential is 17,529 dekatherms, or 0.3% of the baseline projection. By 2040,
cumulative savings are 1,256,282 dekatherms, or 16.5% of the baseline.
Table 6-3 Residential Energy Conservation Potential Summary, Idaho (dekatherms)
Scenario 2021 2022 2025 2030 2040
Baseline Forecast (Dth) 5,757,753 5,864,931 6,201,524 6,677,657 7,614,162
Cumulative Savings (Dth)
UCT Achievable Economic Potential 17,529 44,289 77,379 339,502 1,256,282
TRC Achievable Economic Potential 14,700 32,896 26,285 117,618 255,801
Achievable Technical Potential 70,759 156,239 432,644 1,167,372 2,486,556
Technical Potential 148,844 313,749 798,652 1,806,313 3,485,609
Energy Savings (% of Baseline)
UCT Achievable Economic Potential 0.3% 0.8% 1.2% 5.1% 16.5%
TRC Achievable Economic Potential 0.3% 0.6% 0.4% 1.8% 3.4%
Achievable Technical Potential 1.2% 2.7% 7.0% 17.5% 32.7%
Technical Potential 2.6% 5.3% 12.9% 27.1% 45.8%

Figure 6-3 Residential Energy Conservation by Case, Idaho (dekatherms)

0
500,000
1,000,000
1,500,000
2,000,000
2,500,000
3,000,000
3,500,000
4,000,000
2021 2022 2025 2030 2040
Dth
UCT Achievable Economic TRC Achievable Economic Achievable Technical Technical
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 204 of 794
Figure 6-4 presents forecasts of energy savings by end use as a percent of total annual savings and
cumulative savings. Space heating makes up a majority of potential but declines slightly in the early to mid-2020s due to the future furnace standard.
Figure 6-4 Residential UCT Achievable Economic Potential – Cumulative Savings by End Use, Idaho (dekatherms, % of total)

Table 6-4 identifies the top 20 residential measures by cumulative 2018 and 2019 savings. Furnaces,
tankless water heaters, windows, and insulation are the top measures.

-
200,000
400,000
600,000
800,000
1,000,000
1,200,000
1,400,000
1,600,000
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039
Dth
Space Heating
Secondary Heating
Water Heating
Appliances
Miscellaneous
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039
Share of
Savings
Space Heating
Secondary Heating
Water Heating
Appliances
Miscellaneous
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 205 of 794
Table 6-4 Residential Top Measures in 2021 and 2022, UCT Achievable Economic Potential, Idaho
(dekatherms)
Rank Measure / Technology
2021 Cumulative
Potential Savings
(dekatherms)
% of
Total
2022 Cumulative
Potential Savings
(dekatherms)
% of
Total
1 Furnace - AFUE 92% 14,054 80% 31,241 71%
2 Insulation - Ceiling, Installation - R-38
(Retro only)
1,643 9% 3,640 8%
3 Water Heater - Instantaneous - ENERGY
STAR (UEF 0.87)
1,053 6% 3,293 7%
4 Gas Furnace - Maintenance - Restored
to nameplate 80% AFUE
284 2% 4,805 11%
5 Insulation - Wall Cavity, Installation - R-
11
142 1% 316 1%
6 Water Heater - Low Flow Showerhead
(1.5 GPM) - 1.5 GPM showerhead
93 1% 243 1%
7 Gas Boiler - Steam Trap Maintenance -
Cleaned and restored
91 1% 180 0%
8 Building Shell - Whole-Home Aerosol
Sealing - 20% reduction in ACH50
79 0% 237 1%
9 ENERGY STAR Homes - Built Green spec
(NC Only)
32 0% 176 0%
10 Water Heater - Faucet Aerators - 1.5
GPM faucet
32 0% 87 0%
11 Water Heater - Low Flow Showerhead
(2.0 GPM) - 2.0 GPM showerhead
21 0% 56 0%
12 Water Heater - Pipe Insulation -
Insulated 5' of pipe between unit and
conditioned space
5 0% 14 0%
Subtotal 17,529 100% 44,289 100%
Total Savings in Year 17,529 100% 44,289 100%

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 206 of 794
Commercial Se ctor
Washington Potential
Table 6-5 and Figure 6-5 summarize the energy conservation potential for the commercial sector. In 2021,
UCT achievable economic potential is 28,070 dekatherms, or 0.4% of the baseline projection. By 2040,
cumulative savings are 1,241,314 dekatherms, or 18.0% of the baseline.
Table 6-5 Commercial Energy Conservation Potential Summary, Washington
Scenario 2021 2022 2025 2030 2040
Baseline Forecast (dekatherms) 6,596,157 6,608,411 6,651,275 6,725,824 6,909,984
Cumulative Savings (dekatherms)
UCT Achievable Economic Potential 28,070 66,690 237,773 642,051 1,241,314
TRC Achievable Economic Potential 18,820 46,887 177,954 492,563 999,201
Achievable Technical Potential 47,867 107,183 349,669 887,910 1,704,037
Technical Potential 133,767 274,570 737,799 1,546,608 2,459,821
Energy Savings (% of Baseline)
UCT Achievable Economic Potential 0.4% 1.0% 3.6% 9.5% 18.0%
TRC Achievable Economic Potential 0.3% 0.7% 2.7% 7.3% 14.5%
Achievable Technical Potential 0.7% 1.6% 5.3% 13.2% 24.7%
Technical Potential 2.0% 4.2% 11.1% 23.0% 35.6%
Figure 6-5 Commercial Energy Conservation by Case, Washington (dekatherms)

0
200,000
400,000
600,000
800,000
1,000,000
1,200,000
1,400,000
1,600,000
2021 2022 2025 2030 2040
Thousand
Therms
UCT Achievable Economic TRC Achievable Economic Achievable Technical Technical
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 207 of 794
Figure 6-6 presents forecasts of energy savings by end use as a percent of total annual savings and cumulative savings. Space heating makes up a majority of the potential early, but food preparation equipment upgrades provide substantial savings opportunities in the later years.
Figure 6-6 Commercial UCT Achievable Economic Potential – Cumulative Savings by End Use,
Washington (dekatherms, % of total)

Table 6-6 identifies the top 20 commercial measures by cumulative savings in 2021 and 2022. Heat Pump
Water Heaters are the top measure, followed by several HVAC and space heating measures, along with insulation.
-
100,000
200,000
300,000
400,000
500,000
600,000
700,000
800,000
900,000
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039
Dth
Space Heating
Water Heating
Food Preparation
Miscellaneous
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039
Share of
Savings
Space Heating
Water Heating
Food Preparation
Miscellaneous
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 208 of 794
Table 6-6 Commercial Top Measures in 2021 and 2022, UCT Achievable Economic Potential, Washington (dekatherms)
Ra
nk Measure / Technology
2018 Cumulative
Potential Savings
(dekatherms)
% of Total
2019 Cumulative
Potential Savings
(dekatherms)
% of Total
1 Water Heater - Gas-Fired
Absorption HPWH 5,714 20% 15,883 24%
2 Space Heating - Heat Recovery
Ventilator - HRV installed 4,763 17% 9,542 14%
3 Boiler - AFUE 97% 4,136 15% 10,378 16%
4 HVAC - Duct Repair and Sealing
- 30% reduced duct leaking 2,323 8% 4,589 7%
5 Insulation - Wall Cavity - R-21 2,059 7% 5,578 8%
6 Insulation - Roof/Ceiling - R-38 1,584 6% 4,318 6%
7
Gas Boiler - Insulate Steam
Lines/Condensate Tank - Lines
and condenstate tank insulated
1,456 5% 2,871 4%
8
Water Heater - Central Controls
- Central water boiler controls
installed
1,267 5% 2,508 4%
9 Gas Boiler - Hot Water Reset -
Reset control installed 1,127 4% 2,476 4%
10 Gas Boiler - High Turndown -
Turndown control installed 766 3% 1,509 2%
11 Fryer - ENERGY STAR 751 3% 1,800 3%
12 Water Heater - Faucet Aerator -
1.5 GPM faucet 362 1% 791 1%
13
Building Automation System -
Automation system installed
and programmed
360 1% 1,059 2%
14 Kitchen Hood - DCV/MUA -
DCV/HUA vent hood 316 1% 629 1%
15 HVAC - Demand Controlled
Ventilation - DCV enabled 227 1% 539 1%
16 Furnace - AFUE 96% 129 0% 426 1%
17
Gas Furnace - Maintenance -
General cleaning and
maintenance
125 0% 211 0%
18
Double Rack Oven - FTSC
Qualified (>50% Cooking
Efficiency)
96 0% 257 0%
19 Steam Trap Maintenance -
Cleaning and maintenance 78 0% 153 0%
20 Oven - ENERGY STAR (>42%
Baking Efficiency) 74 0% 196 0%
Subtotal 27,713 99% 65,714 99%
Total Savings in Year 28,070 100% 66,690 100%

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 209 of 794
Idaho Potential
Table 6-7 and Figure 6-7 summarize the energy conservation potential for the commercial sector. In 2021,
UCT achievable economic potential is 16,775 dekatherms, or 0.4% of the baseline projection. By 2040,
cumulative savings are 751,926 dekatherms, or 17.9% of the baseline.
Table 6-7 Commercial Energy Conservation Potential Summary, Idaho
Scenario 2021 2022 2025 2030 2040
Baseline Forecast (dekatherms) 4,027,575 4,047,905 4,093,096 4,112,209 4,199,550
Cumulative Savings (dekatherms)
UCT Achievable Economic Potential 16,775 40,676 144,201 384,730 751,926
TRC Achievable Economic Potential 11,301 28,926 109,041 295,643 606,619
Achievable Technical Potential 29,482 66,801 216,357 539,726 1,037,584
Technical Potential 81,719 172,678 463,550 952,082 1,503,965
Energy Savings (% of Baseline)
UCT Achievable Economic Potential 0.4% 1.0% 3.5% 9.4% 17.9%
TRC Achievable Economic Potential 0.3% 0.7% 2.7% 7.2% 14.4%
Achievable Technical Potential 0.7% 1.7% 5.3% 13.1% 24.7%
Technical Potential 2.0% 4.3% 11.3% 23.2% 35.8%
Figure 6-7 Commercial Energy Conservation by Case, Idaho (dekatherms)

Figure 6-8 presents forecasts of energy savings by end use as a percent of total annual savings and
cumulative savings. Space heating makes up a majority of the potential early, but food preparation equipment upgrades provide substantial savings opportunities in the later years.
0
200,000
400,000
600,000
800,000
1,000,000
1,200,000
1,400,000
1,600,000
2021 2022 2025 2030 2040
Thousand
Therms
UCT Achievable Economic TRC Achievable Economic Achievable Technical Technical
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 210 of 794
Figure 6-8 Commercial UCT Achievable Economic Potential – Cumulative Savings by End Use, Idaho
(dekatherms, % of total)

Table 6-8 identifies the top 20 commercial measures by cumulative savings in 2021 and 2022. Water
Heaters are the top measure, followed by custom HVAC measures and insulation.
-
100,000
200,000
300,000
400,000
500,000
600,000
700,000
800,000
900,000
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039
Dth
Space Heating
Water Heating
Food Preparation
Miscellaneous
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039
Share of
Savings
Space Heating
Water Heating
Food Preparation
Miscellaneous
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 211 of 794
Table 6-8 Commercial Top Measures in 2021 and 2022, UCT Achievable Economic Potential, Idaho
(dekatherms)
Rank Measure / Technology
2021 Cumulative
Potential Savings
(dekatherms)
% of
Total
2022 Cumulative
Potential Savings
(dekatherms)
% of
Total
1 Water Heater - Gas-Fired Absorption
HPWH 3,140 19% 9,188 23%
2 Space Heating - Heat Recovery
Ventilator - HRV installed 2,806 17% 5,620 14%
3 Boiler - AFUE 97% 2,507 15% 6,733 17%
4 HVAC - Duct Repair and Sealing - 30%
reduced duct leaking 1,454 9% 2,872 7%
5 Insulation - Wall Cavity - R-21 1,279 8% 3,464 9%
6
Gas Boiler - Insulate Steam
Lines/Condensate Tank - Lines and
condenstate tank insulated
1,062 6% 2,094 5%
7 Insulation - Roof/Ceiling - R-38 924 6% 2,506 6%
8 Gas Boiler - Hot Water Reset - Reset
control installed 695 4% 1,526 4%
9 Water Heater - Central Controls -
Central water boiler controls installed 634 4% 1,258 3%
10 Gas Boiler - High Turndown - Turndown
control installed 465 3% 915 2%
11 Fryer - ENERGY STAR 458 3% 1,145 3%
12
Building Automation System -
Automation system installed and
programmed
230 1% 676 2%
13 Water Heater - Faucet Aerator - 1.5
GPM faucet 218 1% 477 1%
14 Kitchen Hood - DCV/MUA - DCV/HUA
vent hood 214 1% 426 1%
15 HVAC - Demand Controlled Ventilation -
DCV enabled 142 1% 334 1%
16 Furnace - AFUE 96% 89 1% 304 1%
17 Gas Furnace - Maintenance - General
cleaning and maintenance 78 0% 132 0%
18 Double Rack Oven - FTSC Qualified
(>50% Cooking Efficiency) 67 0% 186 0%
19 Steam Trap Maintenance - Cleaning and
maintenance 55 0% 109 0%
20 Oven - ENERGY STAR (>42% Baking
Efficiency) 52 0% 141 0%
Subtotal 16,567 99% 40,107 99%
Total Savings in Year 16,775 100% 40,676 100%

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 212 of 794
Industrial Sector
Washington Potential
Table 6-9 and Figure 6-9 summarize the energy conservation potential for the core industrial sector. In
2021, UCT achievable economic potential is 2,206 dekatherms, or 0.6% of the baseline projection. By 2040,
cumulative savings reach 24,876 dekatherms, or 8.5% of the baseline. Industrial potential is a lower
percentage of overall baseline compared to the residential and commercial sectors. While large, custom
process optimization and controls measures are present in potential, these are not applicable to all
processes which limits potential at the technical level. Additionally, since the largest customers were
excluded from this analysis due to their status as transport-only customers making them ineligible to
participate in energy efficiency programs for the utility, the remaining customers are smaller and tend to have lower process end-use shares, further lowering industrial potential. As seen in the figure below, industrial potential is substantially lower due to the smaller sector size and process uses.
Table 6-9 Industrial Energy Conservation Potential Summary, Washington (dekatherms)
Scenario 2021 2022 2025 2030 2040
Baseline Forecast (dekatherms) 341,870 338,961 331,037 317,863 291,665
Cumulative Savings (dekatherms)
UCT Achievable Economic Potential 2,206 4,424 11,200 19,428 24,876
TRC Achievable Economic Potential 321 669 1,899 4,508 7,639
Achievable Technical Potential 2,616 5,219 13,165 23,081 29,280
Technical Potential 3,226 6,425 16,116 28,082 35,546
Energy Savings (% of Baseline)
UCT Achievable Economic Potential 0.6% 1.3% 3.4% 6.1% 8.5%
TRC Achievable Economic Potential 0.1% 0.2% 0.6% 1.4% 2.6%
Achievable Technical Potential 0.8% 1.5% 4.0% 7.3% 10.0%
Technical Potential 0.9% 1.9% 4.9% 8.8% 12.2%
Figure 6-9 Industrial Energy Conservation Potential, Washington (dekatherms)

0
5,000
10,000
15,000
20,000
25,000
30,000
2021 2022 2025 2030 2040
Dth
UCT Achievable Economic TRC Achievable Economic Achievable Technical Technical
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 213 of 794
Figure 6-10 presents forecasts of energy savings by end use as a percent of total annual savings and
cumulative savings.
Figure 6-10 Industrial UCT Achievable Economic Potential – Cumulative Savings by End Use,
Washington (dekatherms, % of total)

Table 6-10 identifies the top 20 industrial measures by cumulative 2021 and 2022 savings. Process Heat
Recovery and Retrocommissioning optimization measures have the largest potential savings. Process Heat
Recovery alone accounts for more than 70% of 2021-2022 industrial potential in Washington.

-
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
18,000
20,000
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039
Dth
Space Heating
Process
Miscellaneous
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039
Share of
Savings
Space Heating
Process
Miscellaneous
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 214 of 794
Table 6-10 Industrial Top Measures in 2021 and 2022, UCT Achievable Economic Potential,
Washington (dekatherms)
Rank Measure / Technology
2021 Cumulative
Potential Savings
(dekatherms)
% of
Total
2022 Cumulative
Potential Savings
(dekatherms)
% of
Total
1 Process Heat Recovery - HR system
installed 1,691 72% 3,366 71%
2 Retrocommissioning - Optimized HVAC
flow and controls 156 7% 306 6%
3 Retrocommissioning - Optimized
process design and controls 156 7% 306 6%
4 Gas Boiler - High Turndown - Turndown
control installed 112 5% 222 5%
5 Gas Boiler - Hot Water Reset - Reset
control installed 111 5% 244 5%
6 Destratification Fans (HVLS) - Fans
installed 40 2% 79 2%
7
Gas Boiler - Insulate Steam
Lines/Condensate Tank - Lines and
condenstate tank insulated
28 1% 55 1%
8 Gas Boiler - Insulate Hot Water Lines -
Insulated water lines 19 1% 37 1%
9 ENERGY STAR Connected Thermostat -
Wi-Fi/interactive thermostat installed 17 1% 34 1%
10 Space Heating - Heat Recovery
Ventilator - HRV installed 15 1% 30 1%
11 Boiler - AFUE 97% 5 0% 14 0%
12 Insulation - Wall Cavity - R-21 4 0% 10 0%
13 Furnace - AFUE 96% 3 0% 10 0%
14 Gas Furnace - Maintenance - General
cleaning and maintenance 2 0% 4 0%
15 Thermostat - Programmable -
Programmable thermostat installed 2 0% 4 0%
16 Steam Trap Maintenance - Cleaning and
maintenance 1 0% 1 0%
17 Unit Heater - Infrared Radiant 0 0% 1 0%
18 Insulation - Roof/Ceiling - R-38 0 0% 0 0%
Subtotal 2,362 100% 4,725 100%
Total Savings in Year 2,362 100% 4,730 100%

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 215 of 794
Idaho Potential
Table 6-11 and Figure 6-11 summarize the energy conservation potential for the core industrial sector. In
2021, UCT achievable economic potential is 1,512 dekatherms, or 0.6% of the baseline projection. By 2040,
cumulative savings reach 19,908 dekatherms, or 10.3% of the baseline. Industrial potential is a lower
percentage of overall baseline compared to the residential and commercial sectors. While large, custom
process optimization and controls measures are present in potential, these are not applicable to all
processes which limits potential at the technical level. Additionally, since the largest customers were
excluded from this analysis due to their status as transport-only customers making them ineligible to
participate in energy efficiency programs for the utility, the remaining customers are smaller and tend to
have lower process end-use shares, further lowering industrial potential. As seen in the figure below, industrial potential is substantially lower due to the smaller sector size and process uses.
Table 6-11 Industrial Energy Conservation Potential Summary, Idaho (dekatherms)
Scenario 2021 2022 2025 2030 2040
Baseline Forecast (dekatherms) 234,049 232,058 225,549 214,701 193,107
Cumulative Savings (dekatherms)
UCT Achievable Economic Potential 1,512 3,030 7,703 13,477 17,202
TRC Achievable Economic Potential 220 463 1,557 3,767 6,036
Achievable Technical Potential 1,791 3,573 8,996 15,731 19,908
Technical Potential 2,209 4,398 11,000 19,113 24,123
Energy Savings (% of Baseline)
UCT Achievable Economic Potential 0.6% 1.3% 3.4% 6.3% 8.9%
TRC Achievable Economic Potential 0.1% 0.2% 0.7% 1.8% 3.1%
Achievable Technical Potential 0.8% 1.5% 4.0% 7.3% 10.3%
Technical Potential 0.9% 1.9% 4.9% 8.9% 12.5%
Figure 6-11 Industrial Energy Conservation Potential, Idaho (dekatherms)

Figure 6-12 presents forecasts of energy savings by end use as a percent of total annual savings and
cumulative savings.
0
5,000
10,000
15,000
20,000
25,000
30,000
2021 2022 2025 2030 2040
Dth
UCT Achievable Economic TRC Achievable Economic Achievable Technical Technical
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 216 of 794
Figure 6-12 Industrial UCT Achievable Economic Potential – Cumulative Savings by End Use, Idaho
(dekatherms, % of total)

Table 6-12 identifies the top 20 industrial measures by cumulative 2021 and 2022 savings. Much like
Washington, Process Heat Recovery is the largest measure by far, accounting for more than 70% of total
industrial potential in Idaho.

-
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
18,000
20,000
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039
Dth
Space Heating
Process
Miscellaneous
-
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
18,000
20,000
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039
Dth
Space Heating
Process
Miscellaneous
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 217 of 794
Table 6-12 Industrial Top Measures in 2018 and 2019, UCT Achievable Economic Potential, Idaho
(dekatherms)
Rank Measure / Technology
2021 Cumulative
Potential Savings
(dekatherms)
% of
Total
2022 Cumulative
Potential Savings
(dekatherms)
% of
Total
1 Process Heat Recovery - HR system
installed 1,158 72% 2,304 71%
2 Retrocommissioning - Optimized HVAC
flow and controls 107 7% 210 6%
3 Retrocommissioning - Optimized
process design and controls 107 7% 210 6%
4 Gas Boiler - High Turndown - Turndown
control installed 77 5% 152 5%
5 Gas Boiler - Hot Water Reset - Reset
control installed 76 5% 167 5%
6 Destratification Fans (HVLS) - Fans
installed 27 2% 54 2%
7
Gas Boiler - Insulate Steam
Lines/Condensate Tank - Lines and
condenstate tank insulated
19 1% 38 1%
8 Gas Boiler - Insulate Hot Water Lines -
Insulated water lines 13 1% 25 1%
9 ENERGY STAR Connected Thermostat -
Wi-Fi/interactive thermostat installed 12 1% 23 1%
10 Space Heating - Heat Recovery
Ventilator - HRV installed 10 1% 21 1%
11 Boiler - AFUE 97% 3 0% 10 0%
12 Insulation - Wall Cavity - R-21 3 0% 7 0%
13 Furnace - AFUE 96% 2 0% 7 0%
14
Building Automation System -
Automation system installed and
programmed
2 0% 5 0%
15 Gas Furnace - Maintenance - General
cleaning and maintenance 2 0% 3 0%
16 Thermostat - Programmable -
Programmable thermostat installed 1 0% 3 0%
17 Steam Trap Maintenance - Cleaning and
maintenance 1 0% 1 0%
18 Unit Heater - Infrared Radiant 0 0% 1 0%
Subtotal 1,619 100% 3,240 100%
Total Savings in Year 1,619 100% 3,240 100%

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 218 of 794
Incorporating the Total Resource Cost Test
In addition to the UCT, LoadMAP has been configured to evaluate potential using the TRC. This test focuses
on impacts for both the utility and customer, which is an alternative frame of reference from the UCT. The
TRC includes the full measure cost (incremental for lost opportunities, full cost for retrofits), which is
generally substantially higher than the incentive cost included within the UCT. The TRC does include one
additional value stream that the UCT does not, non-energy impacts. This test is fully incorporated into
LoadMAP and prepared for Avista to use in the event the Company feels a “fully balanced” TRC is
identified.
In accordance with Council methodology, these impacts must be quantified and monetized, meaning
impacts such as personal comfort, which are difficult to assign a value to, are not included. What this does
include are additional savings including water reductions due to low-flow measures or reduced detergent
requirements to wash clothes in a high-efficiency clothes washer. AEG has incorporated these impacts as
they are available in source documentation, such as RTF UES workbooks.
Some impacts are already included within Avista’s avoided costs. These include the 10% conservation
credit applied by the Council for infrastructure benefits of efficiency. The future prices of carbon are also included. Per TRC methodology, as these impacts are already captured within the avoided costs provided
to AEG, we did not incorporate them a second time outside the costs.
Another set of impacts captured within Council methodology include the Simplified Energy Enthalpy
Model (SEEM) “calibration credits”. The Council calibrates this energy model using metered end-use
energy consumption to reflect actual conditions. While these are technically energy impacts, they are not
captured as a benefit to a natural-gas utility as they are instead an impact on the customer. The Council
then assumes the difference between the uncalibrated and calibrated models represents the impacts of
secondary heating by different fuels present in the home. In the Council’s case, these could be small gas
heaters or wood stoves present alongside an electric forced-air furnace. For Avista, AEG followed a similar
methodology, but instead applied the calibration percent impact to estimated gas-heating savings rather
than electric. To monetize these impacts, we incorporated the latest Mid C energy prices, including carbon
impacts, from the RTF’s website, adjusted for differences in efficiency between electric and natural gas
heating equipment (e.g. converted therm savings from an AFUE 80% baseline to kWh savings from an EF
0.97 resistance heater baseline). We applied these impacts to many non-equipment measures with space
heating impacts in all sectors as well as to residential space heating equipment, which was the primary
use for the Council.
Finally, AEG identified additional non-gas end uses which may be impacted by gas efficiency measures.
These include impacts from other end uses, such as cooling savings due to efficient shell measures or
lighting savings due to a comprehensive retrocommissioning or strategic energy management program. Like the calibration credit above, these do not have a benefit to a natural-gas utility but do to the customer.
It is worth a note of caution when incorporating these impacts. Certain comprehensive building measures,
such as retrocommissioning and strategic energy management have very large electric impacts that may
be greater than the original estimated gas impacts. LED lighting is a very popular technology within
electric utility-programs and can have massive impacts. Commercial HVAC retrocommissioning (RCx)
includes both cooling and ventilation electric impacts, which could outweigh the gas space heating
impacts. To realize these cost-effective savings, Avista would need to offer a comprehensive RCx program affecting both electric and natural gas end uses.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 219 of 794
7
COMPARISON WITH CURRENT PROGRAMS
One of the goals of this study is to inform targets for future programs. As such, AEG conducted an in-depth comparison of the CPA’s 2021 UCT Achievable Economic Potential with Avista’s 2019
accomplishments at the sector-level. This involved assigning each measure within the CPA to an existing
Avista program.
Washington Comparison with 2019 Programs
Residential Sector
Table 7-1 summarizes Avista’s 2019 residential accomplishments and the 2021 UCT Achievable Economic
potential estimates from LoadMAP. The LoadMAP estimate of 32,164 dekatherms is lower than Avista’s 2019 accomplishments at 49,161 dekatherms.
Table 7-1 Comparison of Avista’s Washington Residential Programs with 2018 UCT Achievable Economic Potential (dekatherms)
Program Group
2019
Accomplishments
(dekatherms)
LoadMAP
2021 UCT
(dekatherms)
Furnace 31,172 21,548
Boiler 433 51
Water Heater 3,303 1,901
ENERGY STAR Homes 67 47
Smart Thermostat 3,822 4,435
Ceiling Insulation 3,762 3,611
Wall Insulation 447 333
Floor Insulation 342 0
Doors 93 0
Windows 5,556 0
Air Sealing 134 163
Duct Insulation 10 0
Duct Sealing 21 0
Showerheads 0 75
Miscellaneous 1 0
Program Total 49,161 32,164
The main reason that potential is lower is that the baseline assumed for forced-air furnaces is adjusted in
the following ways.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 220 of 794
• The 2015 Washington State Energy Code (WSEC) prescribes very efficient building shell requirements, which substantially reduces the consumption of a new home. Since every new home requires a lost
opportunity purchasing decision when constructed, they make up a large portion of the potential. The
lower unit energy savings in new homes due to lower heating requirements reduces the unit energy savings (UES) from this measure.
• Another reason is the incorporation of a market baseline, which assumes not everyone purchases the
minimum federal standard in the absence of efficiency programs. This results in approximately 20%
of customers purchasing an AFUE 90% and 5% purchasing an AFUE 92% in the baseline, which reduces
the average unit energy consumption upon which savings for an AFUE 95% are based,
Additional descriptions for other measure differences are provided below:
• Potential for ENERGY STAR Homes has been reduced due to WSEC 2015. The efficient shell
requirements lower space heating savings from the prior estimate, which was made before this code went into effect.
• The most recently updated savings and cost characterizations for water heater and windows are reducing their cost effectiveness in some or all segments.
Commercial and Industrial Sectors
Table 7-2 summarizes Avista’s 2019 commercial and industrial accomplishments and the 2021 UCT
Achievable Economic potential estimates from LoadMAP. The LoadMAP estimate of 22,537 dekatherms is
much higher than Avista’s 2019 accomplishments at 7,902 dekatherms.
Table 7-2 Comparison of Avista’s Washington Nonresidential Accomplishments with 2021 UCT Achievable Economic Potential (dekatherms)
Program Group
2019
Accomplishments
(dekatherms)
LoadMAP
2021 UCT
(dekatherms)
HVAC 1,786 11,683
Weatherization 0 3,711
Food Preparation 3,547 1,044
Custom 2,569 6,099
Program Total 7,902 22,537

The following are key drivers in commercial potential:
• The HVAC category includes both efficient equipment (e.g. boilers) as well as custom HVAC measures.
• Fryer and convection oven potential is substantial due to the high gas consumption of restaurants
and Avista’s current success with this program. This measure was heavily accelerated in LoadMAP.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 221 of 794
Idaho Comparison with 2019 Programs
Residential Sector
Table 7-3 summarizes Avista’s 2019 residential accomplishments and the 2021 UCT Achievable Economic
potential estimates from LoadMAP. The LoadMAP estimate of 17,117 dekatherms is lower than Avista’s 2019
accomplishments at 23,667 dekatherms.
Table 7-3 Comparison of Avista’s Idaho Residential Programs with 2021 UCT Achievable Economic
Potential (dekatherms)
Program Group
2019
Accomplishments
(dekatherms)
LoadMAP
2021 UCT
(dekatherms)
Furnace 17,308 14,054
Boiler 247 0
Water Heater 1,735 1,053
ENERGY STAR Homes 40 32
Smart Thermostat 1,931 0
Ceiling Insulation 722 1,643
Wall Insulation 55 142
Floor Insulation 21 0
Doors 4 0
Windows 1,579 0
Air Sealing 21 79
Duct Insulation 1 0
Duct Sealing 2 0
Showerheads - 114
Miscellaneous - 0
Program Total 23,667 17,117
Cost effective measures in LoadMAP show similar potential to Avista’s programs, however some measures,
such as Smart Thermostats and HE Windows, are not showing as cost effective in 2021 forward in
LoadMAP. This is offset somewhat by the fact that, in contrast to Washington, Idaho’s energy code does
not cannibalize a large portion of the HVAC-related savings, resulting in a much steadier range of
potential.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 222 of 794
Commercial and Industrial Sectors
Table 7-4 summarizes Avista’s 2019 commercial and industrial accomplishments and the 2021 UCT
Achievable Economic potential estimates from LoadMAP. The LoadMAP estimate of 14,023 dekatherms is substantially higher than Avista’s 2017 accomplishments at 3,024 dekatherms.
Table 7-4 Comparison of Avista’s Idaho Nonresidential Accomplishments with 2021 UCT Achievable Economic Potential (dekatherms)
Program Group
2019
Accomplishments
(dekatherms)
LoadMAP
2021 UCT
(dekatherms)
HVAC 1,337 7,068
Weatherization 0 2,241
Food Preparation 1,273 638
Custom 414 4,075
Program Total 3,024 14,023

Similar to Washington, many custom HVAC measures were included within the HVAC category to reflect
actual accomplishments.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 223 of 794
8
COMPARISON WITH PREVIOUS STUDY
Residential Comparison with 2018 CPA
Table 8-1 compares first-year residential potential between Avista’s 2018 and 2020 Natural Gas CPAs conducted by AEG. For both states, first year savings are marginally lower (for program categories).
Table 8-1 Comparison of Avista’s Residential UCT Achievable Economic Potential between the 2016 and 2018 CPAs (dekatherms)
Program Group Washington
2018 2020
Idaho
2018 2020
Furnace 19,091 21,548 11,816 14,054
Boiler 619 51 307 0
Water Heater 4,257 1,901 2,014 1,053
ENERGY STAR Homes 294 47 146 32
Smart Thermostat 1,344 4,435 664 0
Ceiling Insulation 1,072 3,611 534 1,643
Wall Insulation 904 333 452 142
Floor Insulation 1,135 0 774 0
Doors 0 0 0 0
Windows 9,426 0 820 0
Air Sealing 0 163 0 79
Duct Insulation 367 0 181 0
Duct Sealing 0 0 0 0
Showerheads 575 75 286 114
Miscellaneous 893 0 362 0
CPA Total 39,979 32,164 18,354 17,117
The slight decrease in potential is due to a few factors:
• Baseline efficiency has been improving
• Some measures are no longer cost effective as a result of updates to characterization of costs and savings
Nonresidential Comparison with 2018 CPA
Table 8-2 compares first-year nonresidential potential between Avista’s 2018 and 2020 Natural Gas CPAs
conducted by AEG. In Washington, the potential is similar, while it is higher in Idaho.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 224 of 794
Table 8-2 Comparison of Avista’s Nonresidential UCT Achievable Economic Potential between the
2016 and 2018 CPAs (dekatherms)
Program Group Washington
2018 2018
Idaho
2017 2018
HVAC 11,925 11,683 3,769 7,068
Weatherization 1,694 3,711 941 2,241
Food Preparation 2,761 1,044 1,045 638
Custom 4,082 6,099 2,033 4,075
CPA Total 21,300 22,537 7,986 14,023

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 225 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 226 of 794
APPENDIX 3.2: ENVIRONMENTAL EXTERNALITIES OVERVIEW
(OREGON JURISDICTION ONLY)
The methodology for determining avoided costs from reduced incremental natural gas usage considers
commodity and variable transportation costs only. These avoided cost streams do not include environmental
externality costs related to the gathering, transmission, distribution or end-use of natural gas.
Per traditional economic theory and industry practice, an environmental externality factor is typically added
to the avoided cost when there is an opportunity to displace traditional supply-side resources with an
alternative resource with no adverse environmental impact.
REGULATORY GUIDANCE
The Oregon Public Utility Commission (OPUC) issued Order 93-965 (UM-424) to address how utilities
should consider the impact of environmental externalities in planning for future energy resources. The
Order required analysis on the potential natural gas cost impacts from emitting carbon dioxide (CO2) and
nitric-oxide (NOx).
The OPUC’s Order No. 07-002 in Docket UM 1056 (Investigation Into Integrated Resource Planning)
established the following guideline for the treatment of environmental costs used by energy utilities that
evaluate demand-side and supply-side energy choices:
UM 1056, Guideline 8 - Environmental Costs
“Utilities should include, in their base-case analyses, the regulatory compliance costs they expect
for carbon dioxide (CO2), nitrogen oxides (NOx), sulfur oxides (SO2), and mercury (Hg) emissions.
Utilities should analyze the range of potential CO2 regulatory costs in Order No. 93-695, from $0
- $40 (1990$). In addition, utilities should perform sensitivity analysis on a range of reasonably
possible cost adders for nitrogen oxides (NOx), sulfur dioxide (SO2), and mercury (Hg), if
applicable.
In June 2008, the OPUC issued Order 08-338 (UM1302) which revised UM1056, Guideline 8. The revised
guideline requires the utility should construct a base case portfolio to reflect what it considers to be the
most likely regulatory compliance future for the various emissions. Additionally the guideline requires the
utility to develop several compliance scenarios ranging from the present CO2 regulatory level to the upper
reaches of credible proposals and each scenario should include a time profile of CO2 costs. The utility is
also required to include a “trigger point” analysis in which the utility must determine at what level of carbon
costs its selection of portfolio resources would be significantly different.
ANALYSIS
Unlike electric utilities, environmental cost issues rarely impact a natural gas utility's supply-side resource
options. This is because the only supply-side energy resource is natural gas. The utility cannot choose
between say "dirty" coal-fired generation and "clean" wind energy sources. The supply-side implication of
environmental externalities generally relates to combustion of fuel to move or compress natural gas.
Avista’s direct gas distribution system infrastructure relies solely on the upstream line pressure of the
interstate pipeline transportation network to distribute natural gas to its customers and thus does not directly
combust fuels that result in any CO2, NOx, SO2, or Hg emissions.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 227 of 794
Upstream gas system infrastructure (pipelines, storage facilities, and gathering systems), however, do
produce CO2 emissions via compressors used to pressurize and move natural gas. Accessing CO2 emissions
data on these upstream activities to perform detailed meaningful analysis is challenging. In the 2009 Natural
Gas IRP there was significant momentum regarding GHG legislation and the movement towards the
creation of carbon cap and trade markets or tax structure. Additionally, the pricing level of the framework
has been greatly reduced. Whichever structure ultimately gets implemented, Avista believes the cost pass
through mechanisms for upstream gas system infrastructure will not make a difference in supply-side
resource selection although the amount of cost pass through could differ widely.
Table 3.2.1 summarizes a range of environmental cost adders we believe capture several compliance futures
including our expected scenario. The CO2 cost adders reflect outlooks we obtained from one of our
consultants, and following discussion and feedback from the TAC, have been incorporated into our
Expected Case, Average Case, Low Growth & High Prices, Electrification - Carbon Reduction, and High
Growth & Low Prices portfolios.
The guidelines also call for a trigger point analysis that reflects a “turning point” at which an alternate
resource portfolio would be selected at different carbon cost adders levels. Because natural gas is the only
supply resource applicable to LDC’s any alternate resource portfolio selection would be a result of delivery
methods of natural gas to customers. Conceptually, there could be differing levels of cost adders applicable
to pipeline transported supply versus in service territory LNG storage gas. From a practical standpoint
however, the differences in these relative cost adders would be very minor and would not change supply-
side resource selection regardless of various carbon cost adder levels. We do acknowledge there is influence
to the avoided costs which would impact the cost effectiveness of demand-side measures in the DSM
business planning process.
CONSERVATION COST ADVANTAGE
For this IRP, we also incorporated a 10 percent environmental externality factor into our assessment of the
cost-effectiveness of existing demand-side management programs. Our assessment of prospective demand-
side management opportunities is based on an avoided cost stream that includes this 10 percent factor.
Environmental externalities were evaluated in the IRP by adding the cost per therm equivalent of the
externality cost values to supply-side resources as described in OPUC Order No. 93-965. Avista found that
the environmental cost adders had no impact on the company’s supply-side choices, although they did
impact the level of demand-side measures that could be cost-effective to acquire.
REGULATORY FILING
Avista will file revised cost-effectiveness limits (CELs) based upon the updated avoided costs available
from this IRP process within the prescribed regulatory timetable.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 228 of 794
TABLE 3.2.1: ENVIRONMENTAL EXTERNALITIES COST ADDER ANALYSIS (2020$)

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 229 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 230 of 794
APPENDIX 4.1: CURRENT TRANSPORTATION/STORAGE RATES AND ASSUMPTIONS

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 231 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 232 of 794
APPENDIX 5: AVISTA RENEWABLE RESOURCE DEVELOPMENT
AND PROCUREMENT DECISION TREE
APPENDIX 5.1: AVISTA RENEWABLE RESOURCE LEAST COST/LEAST RISK
EVALUATION CRITERIA AND CALCULATIONS

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 233 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 234 of 794
APPENDIX 5.2: AVISTA RENEWABLE RESOURCE PROJECT REVENUE
REQUIREMENT MODEL

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 235 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 236 of 794
APPENDIX 5.3: AVISTA RENEWABLE RESOURCE PROJECT RATE IMPACT ANALYSIS
Avista will analyze all RNG-related investment costs and determine the appropriate rate recovery
mechanism, which may include an impact on base rates, purchase gas adjustments or other cost recovery
tariffs. This analysis considers, but is not limited to, factors such as the jurisdictions involved, expenditure
types, cost recovery mechanisms, the spread of the investment to Avista’s customer base and other
potential impacts to ensure the appropriate treatment of the investment.

APPENDIX 5.4: AVISTA RENEWABLE RESOURCE PROJECT CARBON REDUCTION
CALCULATION

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 237 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 238 of 794
APPENDIX 6.1: MONTHLY PRICE DATA BY BASIN
EXPECTED PRICE

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 239 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 240 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 241 of 794
APPENDIX 6.1: MONTHLY PRICE DATA BY BASIN
HIGH GROWTH LOW PRICE

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 242 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 243 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 244 of 794
APPENDIX 6.1: MONTHLY PRICE DATA BY BASIN
LOW GROWTH HIGH PRICE

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 245 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 246 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 247 of 794
APPENDIX 6.2: WEIGHTED AVERAGE COST OF CAPITAL

From 2019 Rate Case Settlement
Cost of Capital
Percent of
Total Capital Cost Component After Tax
L/T Debt 51.50%5.15%2.65%2.10%
Common Equity 48.50%9.40%4.56%4.56%
TOTAL 100.00%7.21%6.65%
From 2019 Rate Case Settlement
Cost of Capital
Percent of
Total Capital Cost Component After Tax
L/T Debt 50.00%5.20%2.60%2.05%
Common Equity 50.00%9.50%4.75%4.75%
TOTAL 100.00%7.35%6.80%
From 2020 Rate Case Settlement
Cost of Capital
Percent of
Total Capital Cost Component After Tax
L/T Debt 50.00% 5.07% 2.54% 2.00%
Common Equity 50.00% 9.40% 4.70% 4.70%
TOTAL 100.00%7.24% 6.70%
Gas Net Rate Base AMA Thru December 2020
WA 435,241$ 48%
ID 179,466$ 20%
OR 292,204$ 32%
906,911$
6.70%
GDP price deflator 2.00%
Real After Tax WACC 4.36%
WASHINGTON
Avista Corporation Capital Structure and Overall Rate of Return
IDAHO
OREGON
System Weighted Average Cost of Capital (Nominal)*
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 248 of 794
APPENDIX 6.3: POTENTIAL SUPPLY SIDE RESOURCE OPTIONS
Fossil Fuel Resources Modeled

Renewable Resources Modeled

Resource Dth per day Dth per year
Levelized Cost Per
Dth (Year 1)
Distributed Renewable Hydrogen Production - WA 166 60,509 $53.48
Distributed Renewable Hydrogen Production - OR 166 60,509 $50.00
Distributed LFG to RNG Production - WA 635 231,790 $13.53
Centralized LFG to RNG Production - WA 1,814 662,256 $11.73
Dairy Manure to RNG Production - WA 635 231,790 $40.70
Wastewater Sludge to RNG Production - WA 513 187,245 $18.95
Food Waste to RNG Production - WA 298 108,799 $40.68
Distributed LFG to RNG Production - OR 635 231,790 $13.53
Centralized LFG to RNG Production - OR 1,814 662,256 $11.73
Dairy Manure to RNG Production - OR 635 231,790 $40.23
Wastewater Sludge to RNG Production - OR 513 187,245 $18.75
Food Waste to RNG Production - OR 298 108,799 $40.21
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 249 of 794
APPENDIX 6.4: EXPECTED CASE AVOIDED COST

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 250 of 794
APPENDIX 6.4: LOW GROWTH & HIGH PRICES CASE AVOIDED COST

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 251 of 794
APPENDIX 6.4: HIGH GROWTH & LOW PRICES CASE AVOIDED COST

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 252 of 794
APPENDIX 6.4: AVERAGE CASE AVOIDED COST

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 253 of 794
APPENDIX 6.4: CARBON REDUCTION AVOIDED COST

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 254 of 794
APPENDIX 6.4: LOW GROWTH & HIGH PRICES MONTHLY DETAIL

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 255 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 256 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 257 of 794
APPENDIX 6.4: EXPECTED CASE MONTHLY DETAIL

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 258 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 259 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 260 of 794
APPENDIX 6.4: HIGH GROWTH & LOW PRICES MONTHLY DETAIL

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 261 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 262 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 263 of 794
APPENDIX 6.4: AVERAGE CASE MONTHLY DETAIL

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 264 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 265 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 266 of 794
APPENDIX 6.4: CARBON REDUCTION MONTHLY DETAIL

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 267 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 268 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 269 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 270 of 794
APPENDIX 7.1: HIGH GROWTH CASES
SELECTED RESOURCES VS. PEAK DAY DEMAND
EXISTING PLUS EXPECTED AVAILABLE

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 271 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 272 of 794
APPENDIX 7.2: PEAK DAY DEMAND TABLE
HIGH GROWTH & LOW PRICES

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 273 of 794
APPENDIX 7.2: PEAK DAY DEMAND TABLE
LOW GROWTH & HIGH PRICES

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 274 of 794
APPENDIX 7.2: PEAK DAY DEMAND TABLE
CARBON REDUCTION

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 275 of 794
APPENDIX 7.2: PEAK DAY DEMAND TABLE
AVERAGE CASE

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 276 of 794
APPENDIX 7.2: PEAK DAY DEMAND TABLE
EXPECTED CASE

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 277 of 794
APPENDIX 7.2: ALTERNATE SUPPLY RESOURCES

Fossil Fuel Resources Modeled

Renewable Resources Modeled

Resource Dth per day Dth per year
Levelized Cost Per
Dth (Year 1)
Distributed Renewable Hydrogen Production - WA 166 60,509 $53.48
Distributed Renewable Hydrogen Production - OR 166 60,509 $50.00
Distributed LFG to RNG Production - WA 635 231,790 $13.53
Centralized LFG to RNG Production - WA 1,814 662,256 $11.73
Dairy Manure to RNG Production - WA 635 231,790 $40.70
Wastewater Sludge to RNG Production - WA 513 187,245 $18.95
Food Waste to RNG Production - WA 298 108,799 $40.68
Distributed LFG to RNG Production - OR 635 231,790 $13.53
Centralized LFG to RNG Production - OR 1,814 662,256 $11.73
Dairy Manure to RNG Production - OR 635 231,790 $40.23
Wastewater Sludge to RNG Production - OR 513 187,245 $18.75
Food Waste to RNG Production - OR 298 108,799 $40.21
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 278 of 794
Resources Not Modeled

Future Supply Resources Size Cost/Rates Availability Notes
Co. Owned LNG
600,000 Dth w/
150,000 of
deliverability
$75 Million plus
$2 Million annual
O&M
2024
On site, in service territory
liquefaction and vaporization
facility
Various pipelines – Pacific
Connector, Cross-Cascades, etc.Varies Precedent
Agreement Rates 2022
Requires additional mainline
capacity on NWPL or GTN to
get to service territory
Large Scale LNG Varies Commodity less
Fuel 2024 Speculative, needs pipeline
transport
In Ground Storage Varies Varies Varies
Requires additional mainline
transport to get to service
territory
Satellite LNG Varies $13M capital cost
plus 665k O&M 2022
provides for peaking services
and alleviates the need for
costly pipeline expansions.
$3,000 per m3 with O&M
assumed at 5.4%.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 279 of 794

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 280 of 794
APPENDIX 8.1: DISTRIBUTION SYSTEM MODELING

OVERVIEW
The primary goal of distribution system planning is to design for present needs and to plan for future
expansion in order to serve demand growth. This allows Avista to satisfy current demand-serving
requirements, while taking steps toward meeting future needs. Distribution system planning identifies
potential problems and areas of the distribution system that require reinforcement. By knowing when and
where pressure problems may occur, the necessary reinforcements can be incorporated into normal
maintenance. Thus, more costly reactive and emergency solutions can be avoided.

COMPUTER MODELING
When designing new main extensions, computer modeling can help determine the optimum size facilities
for present and future needs. Undersized facilities are costly to replace, and oversized facilities incur
unnecessary expenses to Avista and its customers.

THEORY AND APPLICATION OF STUDY
Natural gas network load studies have evolved in the last decade to become a highly technical and useful
means of analyzing the operation of a distribution system. Using a pipeline fluid flow formula, a specified
parameter of each pipe element can be simultaneously solved. Through years of research, pipeline
equations have been refined to the point where solutions obtained closely represent actual system
behavior.

Avista conducts network load studies using GL Noble Denton’s Synergi® 4.8.0 software. This computer-
based modeling tool runs on a Windows operating system and allows users to analyze and interpret
solutions graphically.

CREATING A MODEL
To properly study the distribution system, all natural gas main information is entered (length, pipe
roughness and size) into the model. "Main" refers to all pipelines supplying services.
Nodes are placed at all pipe intersections, beginnings and ends of mains, changes in pipe
diameter/material, and to identify all large customers. A model element connects two nodes together.
Therefore, a "to node" and a "from node" will represent an element between those two nodes. Almost all
of the elements in a model are pipes.

Regulators are treated like adjustable valves in which the downstream pressure is set to a known value.
Although specific regulator types can be entered for realistic behavior, the expected flow passing through
the actual regulator is determined and the modeled regulator is forced to accommodate such flows.

FLUID MECHANICS OF THE MODEL
Pipe flow equations are used to determine the relationships between flow, pressure drop, diameter and
pipe length. For all models, the Fundamental Flow equation (FM) is used due to its demonstrated
reliability.
Efficiency factors are used to account for the equivalent resistance of valves, fittings and angle changes
within the distribution system. Starting with a 95 percent factor, the efficiency can be changed to fine tune
the model to match field results.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 281 of 794
Pipe roughness, along with flow conditions, creates a friction factor for all pipes within a system. Thus,
each pipe may have a unique friction factor, minimizing computational errors associated with generalized
friction values.

LOAD DATA
All studies are considered steady state; all natural gas entering the distribution system must equal the
natural gas exiting the distribution system at any given time.

Customer loads are obtained from Avista’s customer billing system and converted to an algebraic format
so loads can be generated for various conditions. Customer Management Module (CMM), an add-on
application for Synergi, processes customer usage history and generates a base load (non-temperature
dependent) and heat load (varying with temperature) for each customer.

In the event of a peak day or an extremely cold weather condition, it is assumed that all curtailable loads
are interrupted. Therefore, the models will be conducted with only core loads.

DETERMINING NATURAL GAS CUSTOMERS’ MAXIMUM HOURLY USAGE
DETERMINING DESIGN PEAK HOURLY LOAD
The design peak hourly load for a customer is estimated by adding the hourly base load and the hourly
heat load for a design temperature. This estimate reflects highest system hourly demands, as shown in
Table 1:

This method differs from the approach that is used for IRP peak day load planning. The primary reason
for this difference is due to the importance of responding to hourly peaking in the distribution system,
while IRP resource planning focuses on peak day requirements to the city gate.

APPLYING LOADS
Having estimated the peak loads for all customers in a particular service area, the model can be loaded.
The first step is to assign each load to the respective node or element.
GENERATING LOADS
Temperature-based and non-temperature-based loads are established for each node or element, thus loads
can be varied based on any temperature (HDD). Such a tool is necessary to evaluate the difference in flow
and pressure due to different weather conditions.

GEOGRAPHIC INFORMATION SYSTEM (GIS)
Several years ago Avista converted the natural gas facility maps to GIS. While the GIS can provide a
variety of map products, the true power lies in the analytical capabilities. A GIS consists of three
components: spatial operations, data association and map representation.

A GIS allows analysts to conduct spatial operations (relating a feature or facility to another
geographically). A spatial operation is possible if a facility displayed on a map maintains a relationship to
other facilities. Spatial relationships allow analysts to perform a multitude of queries, including:
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 282 of 794
Identify electric customers adjacent to natural gas mains who are not currently using natural gas
Display the number of customers assigned to particular pipes in Emergency Operating Procedure zones
(geographical areas defined to aid in the safe isolation in the event of an emergency)
Classify high-pressure pipeline proximity criteria

The second component of the GIS is data association. This allows analysts to model relationships
between facilities displayed on a map to tabular information in a database. Databases store facility
information, such as pipe size, pipe material, pressure rating, or related information (e.g., customer
databases, equipment databases and work management systems). Data association allows interactive
queries within a map-like environment.

Finally, the GIS provides a means to create maps of existing facilities in different scales, projections and
displays. In addition, the results of a comparative or spatial analysis can be presented pictorially. This
allows users to present complex analyses rapidly and in an easy-to-understand method.

BUILDING SYNERGI® MODELS FROM A GIS
The GIS can provide additional benefits through the ease of creation and maintenance of load studies.
Avista can create load studies from the GIS based on tabular data (attributes) installed during the mapping
process.

MAINTENANCE USING A GIS
The GIS helps maintain the existing distribution facility by allowing a design to be initiated on a GIS.
Currently, design jobs for the company’s natural gas system are managed through Avista’s Maximo tool.
Once jobs are completed, the as-built information is automatically updated on GIS, eliminating the need
to convert physical maps to a GIS at a later date. Because the facility is updated, load studies can remain
current by refreshing the analysis.

DEVELOPING A PRESENT CASE LOAD STUDY
In order for any model to have accuracy, a present case model has to be developed that reflects what the
system was doing when downstream pressures and flows are known. To establish the present case,
pressure recording instruments located throughout the distribution system are used.

These field instruments record pressure and temperature throughout the winter season. Various locations
recording simultaneously are used to validate the model. Customer loads on Synergi® are generated to
correspond with actual temperatures recorded on the instruments. An accurate model’s downstream
pressures will match the corresponding field instrument’s pressures. Efficiency factors are adjusted to
further refine the model's pressures and better match the actual conditions.

Since telemetry at the gate stations record hourly flow, temperature and pressure, these values are used to
validate the model. All loads are representative of the average daily temperature and are defined as hourly
flows. If the load generating method is truly accurate, all natural gas entering the actual system (physical)
equals total natural gas demand solved by the simulated system (model).

DEVELOPING A PEAK CASE LOAD STUDY
Using the calculated peak loads, a model can be analyzed to identify the behavior during a peak day. The
efficiency factors established in the present case are used throughout subsequent models.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 283 of 794
ANALYZING RESULTS
After a model has been balanced, several features within the Synergi® model are used to interpret results.
Color plots are generated to depict flow direction, pressure, and pipe diameter with specific break points.
Reinforcements can be identified by visual inspection. When user edits are completed and the model is re-
balanced, pressure changes can be visually displayed, helping identify optimum reinforcements.
PLANNING CRITERIA
In most instances, models resulting in node pressures below 15 psig indicate a likelihood of distribution
low pressure, and therefore necessitate reinforcements. For most Avista distribution systems, a minimum
of 15 psig will ensure deliverability as natural gas exits the distribution mains and travels through service
pipelines to a customer’s meter. Some Avista distribution areas operate at lower pressures and are
assigned a minimum pressure of 5 psig for model results. Given a lower operating pressure, service
pipelines in such areas are sized accordingly to maintain reliability.
DETERMINING MAXIMUM CAPACITY FOR A SYSTEM
Using a peak day model, loads can be prorated at intervals until area pressures drop to 15 psig. At that
point, the total amount of natural gas entering the system equals the maximum capacity before new
construction is necessary. The difference between natural gas entering the system in this scenario and a
peak day model is the maximum additional capacity that can be added to the system.

Since the approximate natural gas usage for the average customer is known, it can be determined how
many new customers can be added to the distribution system before necessitating system reinforcements.
The above models and procedures are utilized with new construction proposals or pipe reinforcements to
determine the potential increase in capacity.

FIVE-YEAR FORECASTING
The intent of the load study forecasting is to predict the system’s behavior and reinforcements necessary
within the next five years. Various Avista personnel provide information to determine where and why
certain areas may experience growth.
By combining information from Avista’s demand forecast, IRP planning efforts, regional growth plans
and area developments, proposals for pipeline reinforcements and expansions are evaluated with
Synergi®.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 284 of 794
Appendix 8.2

Oregon Public Utility Commission Order No. 16-109 (the Order) included the following
language:

Finally, as part of the IRP-vetting process and subsequent rate proceedings, we expect
that Avista conduct and present comprehensive analyses of its system upgrades. Such
analyses should provide: (1) a comprehensive cost-benefit analysis of whether and when
the investment should be built; (2) evaluation of a range of alternative build dates and
the impact on reliability and customer rates; (3) credible evidence on the likelihood of
disruptions based on historical experience; (4) evidence on the range of possible
reliability incidents; (5) evidence about projected loads and customers in the area; and
(6) adequate consideration of alternatives, including the use of interruptibility or
increased demand-side measures to improve reliability and system resiliency.

In order to address this portion of the Order, Avista has prepared this appendix, which
includes documentation addressing the six points above for each of the natural gas
distribution system enhancements included in the 2021 Natural Gas Integrated Resource
Plan (IRP) for Avista’s Oregon service territory. Each of these three enhancement projects
represents a significant, discrete project which is out of the ordinary course of business (that
is to say, different from ongoing capital investment to address Federal or State regulatory
requirements, relocation of pipe or facilities as requested by others, failed pipe or facilities,
etc., all of which occur routinely over time and which are discussed below).

The routine, ongoing capital investments can be loosely classified in the following categories
(which are not mutually exclusive):

• Safety – Ongoing safety related capital investment includes the repair or replacement
of obsolete or failed pipe and facilities. This category includes, but is not necessarily
limited to, investment to address deteriorated or isolated steel pipe, cathodic
protection, and the replacement of pipeline which has been built over, as well as the
remedy of shallow pipe or the repair or replacement of leaking pipe.
• System Maintenance – Ongoing capital investment related to system maintenance
includes replacement of facilities or pipe that has reached the end of their useful
lives, as well as other general investment required to maintain Avista’s ability to
reliably serve customers.
• Relocation Requested by Others – Ongoing capital investment related to relocation
requested by others falls primarily into two categories, relocation requested by other
parties which is required under the terms of our franchise agreements (such as
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 285 of 794
relocations required to accommodate road or highway construction or relocation),
or relocation requested by customers or others (in which case the customer would
be responsible for the cost of the immediate request, but in which case Avista may
perform additional work, such as the replacement of a steel service with
polyethylene to reduce future maintenance or cathodic protection requirements on
that pipe).
• Mandated System Investment – Ongoing capital investment in this category is driven
by Federal or State regulatory requirements, such as investment that results from
TIMP/DIMP programs, among other programs.
Avista’s Aldyl-A replacement program has been addressed in substantial detail in Oregon
Public Utility Commission Docket UG-246, Avista/500-501.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 286 of 794
1 1
2020 Avista Natural Gas IRP
Technical Advisory Committee Meeting
June 17, 2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 287 of 794
2 2
2020 Natural Gas IRP schedule
•TAC 1: Wednesday, June 17, 2020: TAC meeting expectations, 2020 IRP process and
schedule, actions from 2018 IRP, and a Winter of 2018-2019 review. Procurement Plan
and Resource Optimization benefits, Demand, Weather Analysis and a Weather Planning
Standard, and an energy efficiency update.
•TAC 2: Thursday, August 6, 2020:Market Analysis, Price Forecasts, Cost Of Carbon,
demand forecasts and CPA results from AEG, Environmental Policies, fugitive emissions
•TAC 3: Wednesday, September 30, 2020:Distribution, Avista’s current supply-side
resources overview, supply side resource options, renewable resources, overview of the
major interstate pipelines and projects, and sensitivities and portfolio selection modeling.
•TAC 4: Wednesday, November 18, 2020:Review assumptions and action items, final
modeling results, portfolio risk analysis and 2020 Action Plan.
•TAC 5: February 2021:TAC final review meeting (if necessary)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 288 of 794
3 3
Agenda
•TAC meeting expectations
•2020 IRP process and schedule
•Actions from 2018 IRP
•Winter of 2018-2019 review
•Demand
•Demand Forecast Methodology
•Weather Analysis
•Weather Planning Standard
•Procurement Plan
•Resource Optimization benefits
•Energy efficiency update
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 289 of 794
4 4
Avista’s IRP Process
•Comprehensive analysis bringing demand forecasting and existing and
potential supply-side and demand-side resources together into a 20-
year, risk adjusted least-cost plan
•Considers:
–Customer growth and usage
–Weather planning standard
–Demand-side management opportunities
–Existing and potential supply-side resource options
–Risk
–Public participation through Technical Advisory Committee meetings (TAC)
–Distribution upgrades
•2018 IRP filed in all three jurisdictions on
August 31, 2018 and acknowledged
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 290 of 794
5 5
The Natural Gas System
My House
Pipeline
Receipt
Point
Delivery Point/
Gate Station
Storage
Gathering
System
Local
Distribution
System
Producer
Supply
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 291 of 794
6 6
2018 Avista Natural Gas IRP –Action Plan
1.Avista’s 2020 IRP will contain an individual measure level for dynamic DSM program structure in
its analytics. In prior IRP’s, it was a deterministic method based on based on Expected Case
assumptions. In the 2020 IRP, each portfolio will have the ability to select conservation to meet
unserved customer demand. Avista will explore methods to enable a dynamic analytical process for
the evaluation of conservation potential within individual portfolios.
2.Work with Staff to get clarification on types of natural gas distribution system analyses for possible
inclusion in the 2020 IRP.
3.Work with Staff to clarify types of distribution system costs for possible inclusion in our avoided
cost calculation.
4.Revisit coldest on record planning standard and discuss with TAC for prudency.
5.Provide additional information on resource optimization benefits and analyze risk exposure.
6.DSM—Integration of ETO and AEG/CPA data. Discuss the integration of ETO and AEG/CPA data
as well as past program(s) experience, knowledge of current and developing markets, and future
codes and standards.
7.Carbon Costs –consult Washington State Commission’s Acknowledgement Letter Attachment in
its 2017 Electric IRP (Docket UE-161036), where emissions price modeling is discussed, including the
cost of risk of future greenhouse gas regulation, in addition to known regulations.
8.Avista will ensure Energy Trust (ETO) has sufficient funding to acquire therm savings of the
amount identified and approved by the Energy Trust Board.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 292 of 794
7 7
2018 Avista Natural Gas IRP Action Plan
cont.
•9.Regarding high pressure distribution or city gate station capital work, Avista does not expect any supply side or distribution
resource additions to be needed in our Oregon territory for the next four years, based on current projections. However, should
conditions warrant that capital work is needed on a high pressure distribution line or city gate station in order to deliver safe and
reliable services to our customers, the Company is not precluded from doing such work. Examples of these necessary capital
investments include the following:
••Natural gas infrastructure investment not included as discrete projects in IRP
•–Consistent with the preceding update, these could include system investment to respond to mandates, safety needs, and/or
maintenance of system associated with reliability
••Including, but not limited to Aldyl A replacement, capacity reinforcements, cathodic protection, isolated steel replacement,
etc.
•–Anticipated PHMSA guidance or rules related to 49 CFR Part §192 that will likely requires additional capital to comply
••Officials from both PHMSA and the AGA have indicated it is not prudent for operators to wait for the federal rules to become
final before improving their systems to address these expected rules.
•–Construction of gas infrastructure associated with growth
•–Other special contract projects not known at the time the IRP was published
••Other non-IRP investments common to all jurisdictions that are ongoing, for example:
•–Enterprise technology projects & programs
•–Corporate facilities capital maintenance and improvements
•An updated table 8.4 for those distribution projects in Oregon:
•Location
•Klamath Falls, OR
•Sutherlin, OR
•10. Avista will work with members of the OPUC to determine an alternative stochastic approach to Monte Carlo analysis prior to
Avista’s 2020 IRP and share any recommendations with the TAC members.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 293 of 794
8 8
That Could Never Happen!
Gas Supply Winter 2018-2019
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 294 of 794
9 9
Enbridge Pipeline Rupture
Source: NWGA 2017 Annual Outlook
Sumas
AECO
Rockies
Pipeline Rupture
Jackson Prairie Storage
NWP Roosevelt
Compressor
Pipeline ruptured October 9th
•2.4 Bcf off the system
•Jackson Prairie Storage -down
•NWP Roosevelt compressor maintenance
•Within 24 hours, 50% of demand came off
•Moderate temperatures across Pacific NW
•Average gas prices < $3/Dth
•Gas rebate deferral balances growing
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 295 of 794
1010
Winter 2018-2019 Outlook
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 296 of 794
1111
Historical Winter Firm Customer Load
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 297 of 794
1212
*Avg. weather
-
10
20
30
40
50
60
70
10/1/2018 11/1/2018 12/1/2018 1/1/2019 2/1/2019
De
g
r
e
e
s

F
a
r
e
n
h
e
i
t
Winter '18 -'19 Blended Temps
20 Yr Avg Historical - Blended Actual '18 - '19 - Blended
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 298 of 794
1313
Operation Flow Order (OFO)
•Northwest Pipeline (NWP) Operational Flow Order
An OFO is declared to provide the needed displacement on NWP’s system to
meet firm commitments. When scheduled quantities exceed physical capacity,
NWP is in a potential OFO situation. In other words,
**Avista must flow gas from west to east.**
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 299 of 794
1414
US Storage
569 Bcf below 5 yr avg
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 300 of 794
1515
JP Storage Levels
-
1,000,000
2,000,000
3,000,000
4,000,000
5,000,000
6,000,000
7,000,000
8,000,000
9,000,000
4/1/2018 5/1/2018 6/1/2018 7/1/2018 8/1/2018 9/1/2018 10/1/2018 11/1/2018 12/1/2018 1/1/2019 2/1/2019 3/1/2019
Dt
h
JP Owned - ID & WA JP Lease - OR JP Owned - OR
Avista –1.0 bcf
Puget –2.2 bcf
Nwp –3.5 bcf
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 301 of 794
1616
Jackson Prairie Compressor C-9
Reduction of withdrawal capability by approx. 200-300 MMscfd
Avista withdrawal ability < 90 MMscfd (JP demand 50 –90 MMscfd)
Compressor
Failed
2/10/19
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 302 of 794
1717
Enbridge Capacity Cuts
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 303 of 794
1818
Pipeline Entitlements
•Entitlements are used to balance demand
–Entitlement tolerances are tiered
•13%, 8%, 5%, 3% depending on severity of issue
–Overrun entitlement
•Total demand must not exceed nominations by the prescribed level
•Example: Avista nominates 150,000 Dth on pipeline, demand must
be AT MOST 169,500 Dth
–Entitlement penalties
•Greater of $10.00/ dth or 4x the highest midpoint price in region
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 304 of 794
1919
Historical and Current Winter Loads
-
50,000
100,000
150,000
200,000
250,000
300,000
350,000
400,000
No
v
-
0
1
No
v
-
0
7
No
v
-
1
3
No
v
-
1
9
No
v
-
2
5
De
c
-
0
1
De
c
-
0
7
De
c
-
1
3
De
c
-
1
9
De
c
-
2
5
De
c
-
3
1
Ja
n
-
0
6
Ja
n
-
1
2
Ja
n
-
1
8
Ja
n
-
2
4
Ja
n
-
3
0
Fe
b
-
0
5
Fe
b
-
1
1
Fe
b
-
1
7
Fe
b
-
2
3
Ma
r
-
0
1
Ma
r
-
0
7
Ma
r
-
1
3
Ma
r
-
1
9
Ma
r
-
2
5
Ma
r
-
3
1
Dt
h

/

d
a
y
Total System Firm Customer Load
5 Year Min-Max 5-Yr Avg
2018-2019 Forecasted Peak Day (2/15)Sumas/JP Sourced
2018-2019
Forecasted Peak Day: 347,228 Dth
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 305 of 794
2020
Planning Outcomes changes
•In order to reduce the risk around not being able
to serve load on a peak day with late winter
weather Avista is moving it’s peak day from 2/15
to 2/28 for the WA/ID and La Grande
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 306 of 794
2121
Avista’s Demand Overview
Tom Pardee
Manager of Natural Gas Planning
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 307 of 794
2222
–Population of service area 1.5 million
385,000 electric customers
360,000 natural gas customers
•Has one of the smallest carbon
footprints among America’s 100
largest investor-owned utilities
•Committed to environmental
stewardship and efficient use
of resources
Service Territory and Customer Overview
•Serves electric and natural gas customers in eastern Washington and northern Idaho,
and natural gas customers in southern and eastern Oregon
State Total Customers % of Total
Washington 170,000 47%
Oregon 103,000 29%
Idaho 87,000 24%
Total 360,000 100%
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 308 of 794
2323
Klamath Falls
Res Com Ind
Average demand 2,628 1,352 44
Customers 15,192 1,787 6
0
500
1,000
1,500
2,000
2,500
3,000
-
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
Av
e
r
a
g
e

d
a
i
l
y

u
s
e

(
D
t
h
)
Cu
s
t
o
m
e
r
s
Average 2019 Temp Fahrenheit 47
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 309 of 794
2424
Roseburg
Res Com Ind
Average demand 2,537 2,051 7
Customers 13,889 2,189 2
0
500
1,000
1,500
2,000
2,500
3,000
-
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
Av
e
r
a
g
e

d
a
i
l
y

u
s
e

(
D
t
h
)
Cu
s
t
o
m
e
r
s
Average 2019 Temp Fahrenheit 55
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 310 of 794
2525
La Grande
Res Com Ind
Demand 1,371 896 116
Customers 6,794 943 3
0
200
400
600
800
1,000
1,200
1,400
1,600
-
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
Av
e
r
a
g
e

d
a
i
l
y

u
s
e

(
D
t
h
)
Cu
s
t
o
m
e
r
s
Average 2019 Temp Fahrenheit 47
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 311 of 794
2626
Medford
Res Com Ind
Average demand 9,312 5,939 62
Customers 56,354 7,038 14
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
10,000
-
10,000
20,000
30,000
40,000
50,000
60,000
Av
e
r
a
g
e

d
a
i
l
y

u
s
e

(
D
t
h
)
Cu
s
t
o
m
e
r
s
Average 2019 Temp Fahrenheit 55
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 312 of 794
2727
Idaho
Res Com Ind
Average demand 16,872 9,668 800
Customers 77,804 9,164 89
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
18,000
-
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
Av
e
r
a
g
e

d
a
i
l
y

u
s
e

(
D
t
h
)
Cu
s
t
o
m
e
r
s
Average 2019 Temp Fahrenheit 47
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 313 of 794
2828
Washington
Res Com Ind
Average demand 32,792 19,999 810
Customers 155,069 14,980 130
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
-
20,000
40,000
60,000
80,000
100,000
120,000
140,000
160,000
180,000
Av
e
r
a
g
e

d
a
i
l
y

u
s
e

(
D
t
h
)
Cu
s
t
o
m
e
r
s
Average 2019 Temp Fahrenheit 47
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 314 of 794
2929
OR Daily Demand Profiles
-2,000
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
- 10 20 30 40 50 60 70 80 90 100
De
k
a
t
h
e
r
m
s
Roseburg
Daily Demand
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
- 20 40 60 80 100
Dt
h
Avg. Temp (F)
La Grande
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 315 of 794
3030
WA-ID Daily Demand Profiles
0
10000
20000
30000
40000
50000
60000
70000
80000
90000
020406080100
De
m
a
n
d

(
Dt
h
)
Avg. Temp (F)
Idaho Demand
0
20,000
40,000
60,000
80,000
100,000
120,000
140,000
160,000
180,000
020406080100
De
m
a
n
d

(
D
t
h
)
Avg. Temp (F)
WA Demand
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 316 of 794
3131
Demand Forecast Methodology
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 317 of 794
3232
(CDD)
(HDD)
Temp
(℉)
Degree
Days
100 =35
90 =25
80 =15
70 =5
65 =0
60 =5
50 =15
40 =25
30 =35
20 =45
10 =55
0 =65
-10 =75
-20 =85
Temperature & Degree Days
Cooling
Degree Days
Heating
Degree Days
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 318 of 794
3333
Weather
•NOAA 20 year actual average daily HDD’s (2000-
2019)
•Peak weather includes two winter storms (5 day
duration), one in December and one in February
•Planning Standard
•Sensitivity around planning standard including
–Normal/Average
–Monte Carlo simulation
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 319 of 794
3434
Base Coefficients
*Historic Data -July and August Average
Planning Area -Residential Class 2 year 3 year 5 year
Roseburg (Oregon)0.041949146 0.040148823 0.03765259
Medford (Oregon)0.04748832 0.047701223 0.04716918
La Grande (Oregon)0.069994892 0.068986632 0.073506326
Klamath Falls (Oregon)0.035881027 0.034536108 0.033843554
Idaho 0.048375922 0.046698825 0.046092068
Washington 0.047248771 0.046575066 0.047525773
*Base Coefficients
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 320 of 794
3535
Heat Coefficients
Planning Area -Residential Class 2 Year 3 Year 5 Year
Roseburg (Oregon)0.008829 0.008046 0.00699
Medford (Oregon)0.00639 0.0065 0.006068
La Grande (Oregon)0.006223 0.007297 0.00665
Klamath Falls (Oregon)0.005284 0.005268 0.004902
Idaho 0.006445 0.006344 0.005896
Washington 0.006307 0.006313 0.005957
*Avg. of monthly heat coefficient
*Historic Data –adjusted by price elasticity and DSM
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 321 of 794
3636
Demand Modeling Equation –a closer look
SENDOUT® requires inputs expressed in the below format to
compute daily demand in dekatherms. The base and weather
sensitive usage (degree-day usage) factors are developed
outside the model and capture a variety of demand usage
assumptions.
# of customers x Daily weather sensitive usage / customer
# of customers x Daily base usage / customer
Plus
Table 3.2 Basic Demand Formula
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 322 of 794
3737
1.Expected customer count forecast by each of the 6 areas
2.Use per customer coefficients –5 year, 3 year or last 2 year average use
per HDD per customer
3.Current weather planning standard
Developing a Reference Case
Customer
count
forecast
Use per
customer
coefficients
Weather Reference
Case Demand
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 323 of 794
3838
Weather Analysis
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 324 of 794
3939
Z-Stat
•Compare one period to another
•Shows how far from the average the data point
falls
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 325 of 794
4040
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 326 of 794
4141
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 327 of 794
4242
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 328 of 794
4343
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 329 of 794
4444
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 330 of 794
4545
Summary
•Avista’s warmer climate locations, Roseburg and
Medford, continue to see a shift in temperatures
vs. the reference period
•The colder weather climate locations, Klamath
Falls, La Grande, Spokane (ID, WA), have
maintained the general shape and remain
consistent vs. the reference period
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 331 of 794
4646
Weather Planning Standard
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 332 of 794
4747
Weather Standard
•Has the potential to significantly change timing of
resource needs
•Significant qualitative considerations
–No infrastructure response time if standard
exceeded
–Significant safety and property damage risks
•Current Peak HDD Planning Standards
–WA/ID 82
–Medford 61
–Roseburg 55
–Klamath 72
–La Grande 75
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 333 of 794
4848
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 334 of 794
4949
Wind chill effects
•W ind on homes causes two effects.One is wind
chill on the exterior of the building and the other
is infiltration increases due to the pressure
difference caused by wind blowing past the
home.
•The greatest effect of wind on heating is low
humidity in the home which makes the
customers feel like the temperature is 64
degrees when they have the thermostat set at
72 if their humidity is lower than 10% Relative
Humidity.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 335 of 794
5050
Weather Peak Planning Day alternative
•Coldest Average Day, each year, for the past 30
years combined with a 99% probability
Area Coldest on Record 99% Probability
Avg. Temp
99% Probability
Avg. Temp & Wind
Chill*
La Grande -10 -11 -23
Klamath Falls -7 -9 -16
Medford 4 11 9
Roseburg 10 14 16
Spokane -17 -12 -26
*this was done with the recent 20 years of data combined with windspeed for example purposes
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 336 of 794
5151
Risks
•Using wind chill effects combined with a 99%
probability produces some drastic changes in
peak day planning and may require a large
amount of capital to meet those design criteria
•Utilizing a 99% probability means there is a 1 in
100 event where Avista may not be able to meet
the demand
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 337 of 794
5252
Risk around moving WA and ID peak day
temps (1,000 simulated futures run)
Draws 201 -400Draws 1 -200
33 38
Coldest on Record Peak Days
(82 HDD’s, or -17 Avg. Temp Fahrenheit)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 338 of 794
5353
“Flat Demand” Risk
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 339 of 794
5454
Avista Weather Recommendation
•Utilize coldest day for each of the past 30 years
with a 99% probability supply can be fulfilled
Area 99% Probability Avg.
Temp
La Grande -11
Klamath Falls -9
Medford 11
Roseburg 14
Spokane -12
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 340 of 794
5555
Procurement Plan
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 341 of 794
5656
Hedging Objectives and Goals
Mission
To provide a diversified portfolio of reliable supply
and a level of price certainty in volatile markets.
•Avista cannot predict future market prices, however we use
experience, market intelligence, and fundamental market analysis to
structure and guide our procurement strategies.
•Avista’s goal is to develop a plan that utilizes customer resources
(storage and transportation), layers in pricing over time for stability
(time averaging), allows discretion to take advantage of pricing
opportunities should they arise, and appropriately manages risk.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 342 of 794
5757
Oversight and Control
Risk
Management
Committee
(RMC)
•Comprised of Executive
Officers & Sr. Management
•Responsible for the Risk
Management Policy
•Provides oversight and
guidance on natural gas
procurement plan
Strategic
Oversight
Group (SOG)
•Cross functional group
consisting of:
•Credit, Electric/Gas
Supply, Rates, Resource
Accounting, Risk
•Co-develops the
Procurement Plan
•Meets regularly
Natural Gas
Supply
•Monitors and manages the
Procurement Plan on a daily
basis
•Leads in the annual
Procurement Plan review
and modification
Commission
Update
•Semi-Annual Update
•New Procurement Plan is
communicated semi-
annually in the fall and
spring
•Intra-year changes
communicated to staff on
an ad-hoc basis
•
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 343 of 794
5858
Comprehensive Annual Review of
Previous Plan
Review conducted with SOG includes:
•Mission statement and approach
•Current and future market dynamics
•Hedge percentage
•Operative Boundary
•Resources available (i.e. storage and transportation)
•Hedge windows and quantity (how many, how long)
•Storage utilization
•Analysis (volatility, past performance, scenarios, risk)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 344 of 794
5959
Risk
Assessment
Load
Volatility
•Seasonal
Swings
Price
•Cash vs.
Forward
Market
Liquidity
•Is there
enough?
Counterparty
•Who can we
transact with?
Foreign
Currency
•What’s our
exposure?
Legislation
•Does it impact
our plan?
A Thorough Evaluation of Risks
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 345 of 794
6060
AECO Daily Volatility
$0.00
$2.00
$4.00
$6.00
$8.00
$10.00
$12.00
$
p
e
r

D
T
h
Max-Min Actual
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 346 of 794
6161
-
50,000
100,000
150,000
200,000
250,000
300,000
350,000
400,000
Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct
Dt
h

/

D
a
y
Natural Gas Procurement Plan vs. System Demand
November 2019 through October 2020
Average Load (includes fuel)Hedges Index Max Load Min Load Peak Day
*As of 10/9/2019
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 347 of 794
6262
Plan Overview
Dynamic Window Hedge
(DWH) Plan
–Manages hedges based on
average volumetric load
–Firm local distribution customers
only
–Delivery Periods: Hedges up to
3 years out into the future from
the prompt month in monthly
and/or seasonal timeframes
–Supply Basins:Windows will
use VAR as a way to determine
the best basin for a hedge.
(AECO, Rockies, Sumas).
Risk Responsive Hedging
Tool (RRHT)
–Manages all hedges in the
portfolio based on a financial
position
•Transport optimization
hedges
•Storage optimization hedges
•LDC hedges from the DWH
program
–Incorporates the financial
value at risk (VaR) as a daily
position based on current firm
supply side assets combined
with price volatility at each
futures market basin
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 348 of 794
6363
Dynamic Window Hedging
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 349 of 794
6464
Risk Responsive Hedging Tool
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 350 of 794
6565
Optimization
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 351 of 794
6666
Avista Gas Supply Asset Optimization
•Storage Optimization.
o Utilize Avista owned portion of Jackson Prairie storage facility​
o Maintain a peak day capability in order to serve needed demand from the facility during a peak event.​
o Optimize excess capacity through arbitrage between daily prices and forward months as well as between different forward months.​
•Transport Optimization.​
o Avista owns transport capacity sufficient to serve peak day load.Unused capacity is optimized by purchasing/selling gas at different hubs to capture locational price spreads.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 352 of 794
6767
Storage Optimization Examples
•Day ahead market arbitrage with forward month
Purchase: daily sumas 75,000 dth for $1.45/dth.
Sale: 75,000 dth October 2020 Sumas for $2.48/dth.​
Realized arbitrage value:$1.03*75,000 = $77,250​
•Arbitrage between different forward months​
​Purchase: Q3 2020 sumas 225,000 dth for $1.81
Sale: Q1 2021 sumas 225,000 dth for $3.47
Realized arbitrage value : $1.66*225,000 = $373,500
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 353 of 794
6868
Transport Optimization
•Transport Capacity in excess of
Avista core load can be optimized
to reduce customer costs.
•Optimization can be done in either
the daily or forward markets
Example:
Purchase: 30,000 dth AECO for
$2.00/dth
Sale: 30,000 dth Malin for $2.30/dth
Realized cost reduction to customers:
$0.30*30,000 = $9,000
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 354 of 794
6969
Risks
•Operational Flow Orders:
o NW Pipeline may require the use of JP storage gas to
satisfy OFO’s.
o May require additional purchases from market to
replace storage inventory.
•Unplanned maintenance:
o Unexpected reductions to pipeline capacity or
reduced access to storage may limit optimization
activity
•Damage or failure of infrastructure
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 355 of 794
7070
2020 Natural Gas IRP
Energy Efficiency
Ryan Finesilver –Energy Efficiency Planning and Analytics Manager
First Technical Advisory Committee Meeting
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 356 of 794
7171
Team Roles
Planning &
Analytics Team
Applied Energy
Group (AEG)Gas Supply
Oregon DSM Programs
ACP CPA IRP
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 357 of 794
7272
Alphabet Soup
•CPA: Conservation Potential Assessment
•IRP: Integrated Resource Plan
•AEG: Applied Energy Group
•IPUC: Idaho Public Utility Commission
•TRC: Total Resource Cost Test
•UCT: Utility Cost Test
•UTC: Utilities and Transportation Commission
The CPA within the IRP is done by AEG and as per the UTC, is
according to the TRC but the IPUC requires the UCT.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 358 of 794
7373
Who Energy Efficiency Serves
•Washington
•Idaho
•Oregon (ETO except
for Low-Income)
Three
Jurisdictions
•Residential
•Industrial/Commercial
•Low-Income
Residential
Multiple
Customer
Segments
•Aids in reducing
overall capacity
•Defers capital
investments
The
Company’s
Infrastructure
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 359 of 794
7474
Energy Efficiency Funding –Natural Gas
$8.4 Million
Annual
Funding
(2019)
Tariff percentage of customer bill by state:
2.6%
3.7%
4.3%
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 360 of 794
7575
WA Gas Targets to Actual Savings
2014 2015 2016 2017 2018 2019 2020
Business Plan Target 637,042 602,010 567,653 620,310 719,451 726,128 937,402
IRP Target 1,310,000 1,287,000 737,000 489,110 612,830 725,180 936,350
Actual 615,418 919,892 548,756 1,046,356 736,985 504,113
0
200,000
400,000
600,000
800,000
1,000,000
1,200,000
1,400,000
Th
e
r
m

S
a
v
i
n
g
s
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 361 of 794
7676
ID Gas Targets to Actual Savings
2014 2015 2016 2017 2018 2019 2020
Business Plan Target 0 0 232,737 219,272 252,712 321,120 436,405
IRP Target 456,000 228,000 114,000 197,640 246,440 320,830 421,270
Actual 0 0 189,295 245,747 247,756 278,922
0
50,000
100,000
150,000
200,000
250,000
300,000
350,000
400,000
450,000
500,000
Th
e
r
m

S
a
v
i
n
g
s
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 362 of 794
7777
OR Energy Trust Gas Targets to Actual
Savings
0
50,000
100,000
150,000
200,000
250,000
300,000
350,000
400,000
450,000
Th
e
r
m

S
a
v
i
n
g
s
Savings Goal IRP Target Actual
-Energy Trust did not deliver
programs for Avista in 2014-2015
-Energy Trust began providing
savings projections for Avista's IRP
in 2017
2014 2015 2016 2017 2018 2019
Savings Goal 31,574 318,332 349,520 360,682
IRP Target 318,332 349,520 294,720
Actual 34,708 340,738 409,128 384,599
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 363 of 794
7878
Energy Efficiency
Business Planning
CPA Target Business
Plan
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 364 of 794
7979
Conservation Potential Assessment
(CPA)
•Primary Objectives
–Meet legislative and regulatory requirements
–Support integrated resource planning
–Identify opportunities for savings; key measures in
target segments
•Key Deliverables
–20-year conservation potential
–Individual measures
–IRP target
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 365 of 794
8080
Conservation Potential Assessment
•Theoretical upper limit of conservation
•All efficiency measures are phased in regardless of cost
Technical
Potential
•Realistically achievable, accounting for adoption rates
and how quickly programs can be implemented
•Does not consider cost-effectiveness of measures
Achievable
Technical
Potential
•Includes economic screening of measures (cost
effectiveness)
•Sets our conservation target
Achievable
Potential
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 366 of 794
8181
Business Planning Process
Business
Planning
Annual
Conservation
Plan
EM&V
Annual
Conservation
Report
Conservation
Potential
Assessment
Adaptive
Management
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 367 of 794
8282
Business Planning Process
CPA
•Sets overall
Savings Goal
•Identifies
Measures
Avista Programs
•Consult with
our existing
programs
•Add new
measures to
existing
programs
Update and
Evaluate
•Update
existing
savings
values
•Test for Cost-
Effectiveness
(TRC/UCT)
Feedback and
Modify
•DSM
Program
Managers
•Engineers
•Industry
Trends
•Other Parties
Energy Efficiency Advisory Group
Business Planning Process
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 368 of 794
8383
Incentive Setting
Decide Incentive Level
$3 per
Therm
70% of
CIC CE Impact Portfolio
Alignment
Cost-Effective Test
Utility Cost Test (UCT)
Total Resource Cost (TRC)
Must have a B/E ratio
of 1.0 or Higher
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 369 of 794
8484
Significant Costs and Benefits
From Cost-effectiveness training (3/6/15) Powerpoint
http://www.cpuc.ca.gov/General.aspx?id=5267
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 370 of 794
8585
Energy Trust’s Resource Assessment
Model
•What is a resource assessment model?
o Energy Trust’s version of a Conservation Potential Assessment
o Model that provides an estimate of energy efficiency resource potential achievable over a 20-year period
o ‘Bottom-up’ approach to estimate potential starting at the measure level and scaling to a service territory
•Energy Trust uses a Model that calculates Technical, Achievable and Cost-Effective Achievable Energy Efficiency Potential
o Final program/IRP targets are established via a deployment forecast in a separate tool
•We provide a 20-year energy efficiency forecast for utility IRPs about every two years.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 371 of 794
8686
Energy Trust’s Resource Assessment
Model is “Living Model”
•Energy Trust makes continuous improvements to the model
•Measures in the model are updated on an ongoing basis to reflect changing market conditions and savings estimates
•Emerging technologies are added to the model as data availability and product viability allows
•Cost-effective potential may be realized through programs, market transformation and/or codes and standards
•Under discussion: use of a “large project adder” to account for large, unexpected projects
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 372 of 794
8787
Energy Trust Resource Assessment
Model Inputs
Measure Level Inputs
Measure Definition and Application:
•Baseline/Efficient equip. definition
•Applicable customer segments
•Installation type (RET/ROB/NEW)*
•Measure Life
Measure Savings
Measure Cost
•Incremental cost for ROB/NEW
measures
•Full cost for retrofit measures
Market Data (for scaling)
•Units per site
•Baseline/efficient equipment
saturations
•Suitability
Utility ‘Global’ Inputs
Customer and Load Forecasts
•Used to scale measure level
savings to a service territory
•Residential Stocks: # of homes
•Commercial Stocks: 1000s of Sq.Ft.
•Industrial Stocks: Customer load
Avoided Costs
Customer Stock Demographics:
•Heating fuel splits
•Water heat fuel splits
* RET = Retrofit; ROB = Replace on
Burnout; NEW = New Construction
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 373 of 794
8888
Energy Trust 20-Year IRP EE Forecast Flow Chart
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 374 of 794
8989
Energy Trust Forecasted Potential Types
Not
Technically
Feasible
Technical Potential
Calculated
within RA
Model
Market
Barriers
Achievable Potential
(85%of Technical Potential)
Not Cost-
Effective
Cost-Effective Achiev.
Potential
Program Design &
Market Penetration
Final Program
Savings
Potential
Developed
with
Programs
& Market
Information
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 375 of 794
9090
Energy Trust Cost-Effectiveness Screen
For RA Modeling
•Energy Trust utilizes the Total Resource Cost (TRC) test to screen measures in the
model for cost effectiveness
•If TRC is > 1.0, it is cost-effective and the resources is included in cost-effective
achievable potential
•Measure Benefits:
o Avoided Costs
▪Annual measure savings x NPV avoided costs per therm or kWh
o Quantifiable Non-Energy Benefits
▪Water savings, etc.
•Total Measure Costs:
o The customer cost of installing an EE measure (full cost if retrofit, incremental
over baseline if replacement)
•Some gas measures are forced into the model if they have exceptions from the
OPUC under the criteria established via UM 551
TRC =

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 376 of 794
9191
Energy Trust Deployment
•The RA model results represent the maximum
savings potential in a given year.
•Ramp rates are an estimate of how much of that
available potential will come off Avista’s system
in a given year.
•Energy Trust ramp rates are based on NWPCC
methods and ramp rates, but calibrated to be
specific to Energy Trust.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 377 of 794
9292
Energy Trust Final Savings
Projection Methodology
Years 1-2
•Program forecasts –they know what is happening short term best
Years 3-5
•Planning and Programs work together to create forecast
Years 6-20
•Planning forecasts long-term acquisition rate to generally align NWPCC
Energy Trust calibrates the first five years of energy
efficiency acquisition ramp rates to program performance
and budget goals.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 378 of 794
9393
Energy Trust Ramp Rate Overview
•Total RA Model cost-effective potential is different depending on the measure type.
–Retrofit measure savings are 100% of all potential in every year, therefore must be distributed in a curve that adds to 100% over the forecast timeframe (bell curve)
–Lost opportunity measure savings are the savings available in that year only and deployment rates are what % of that available potential rate can be achieved –results in an s-curve
•Generally follows the NWPCC deployment methodology
–100% cumulative penetration for retrofit measures over 20-year forecast
–100% annual penetration for lost opportunity by end of 20-year forecast (program or code achieved)
–Hard to reach measures or emerging technologies do not ramp to 100%
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 379 of 794
9494
Energy Trust Ramp Rate Examples
0%
20%
40%
60%
80%
100%
120%
0%
1%
2%
3%
4%
5%
6%
7%
8%
9%
10%
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21
Lo
s
t

o
p
p
o
r
t
u
n
i
t
y

%

a
d
o
p
t
i
o
n
s
Re
t
r
o
f
i
t

C
u
r
v
e

%

a
d
o
p
t
i
o
n
s
Year
Retrofit Curve Lost Opportunity Curve
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 380 of 794
9595
Avista’s OR IRP Savings Targets Influence
Annual Energy Trust Savings Goals and
Budgets
•The savings forecasts that Avista incorporates into their IRPs is a reference point for setting annual Energy Trust savings goals and budgets
•Likewise, the Energy Trust savings goals from the last budget cycle inform the early years of the next IRP forecast
•This results in a cycle of iterative updates to savings projections based on the most recent market intelligence
•In addition, Energy Trust’s measure development process uses the Utility Cost Test to screen measures for cost-effectiveness
–This test sets an upper bound on the incentive that can be offered and this factors into the budget process
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 381 of 794
9696
Questions?
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 382 of 794
9797
2020 Natural Gas IRP schedule
•TAC 1: Wednesday, June 17, 2020: TAC meeting expectations, 2020 IRP process and
schedule, actions from 2018 IRP, and a Winter of 2018-2019 review. Procurement Plan
and Resource Optimization benefits, Demand, Weather Analysis and a Weather Planning
Standard, and an energy efficiency update.
•TAC 2: Thursday, August 6, 2020:Market Analysis, Price Forecasts, Cost Of Carbon,
demand forecasts and CPA results from AEG, Environmental Policies, fugitive emissions
•TAC 3: Wednesday, September 30, 2020:Distribution, Avista’s current supply-side
resources overview, supply side resource options, renewable resources, overview of the
major interstate pipelines and projects, and sensitivities and portfolio selection modeling.
•TAC 4: Wednesday, November 18, 2020:Review assumptions and action items, final
modeling results, portfolio risk analysis and 2020 Action Plan.
•TAC 5: February 2021:TAC final review meeting (if necessary)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 383 of 794
2021 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 2 Agenda
Thursday, August 6, 2020
Virtual Meeting- 9:00 AM PST

Topic Time Staff
Introductions & IRP Process Updates 9:00 Lyons

Natural Gas & RNG Market Overview 9:30 Pardee
Break 10:45 Natural Gas Price Forecast 11:00 Brutocao
Lunch 11:30
Upstream Natural Gas Emissions 12:30 Pardee
Break 1:30
Regional Energy Policy Update 1:45 Lyons
Natural Gas and Electric Coordinated 2:15 Gall/Pardee Study

Highly Impacted & Vulnerable Populations 3:00 Gall Baseline Analysis
Adjourn 3:45
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 384 of 794
2021 Electric and Natural Gas IRPs
TAC Introductions and IRP Process
Updates
John Lyons, Ph.D.
Second Technical Advisory Committee Meeting
August 6, 2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 385 of 794
Updated Meeting Guidelines
•Gas and electric IRP teams working remotely, but still
available by email and phone for questions and
comments
•Some processes are taking longer remotely
•Virtual IRP meetings until back in the office and able to
hold large group meetings
•TAC presentations, notes, work plans and past IRPs are
posted on joint IRP page for gas and electric:
https://www.myavista.com/about-us/integrated-resource-
planning
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 386 of 794
Virtual TAC Meeting Reminders
•Please mute mics unless speaking or asking a question
•Use the Skype chat box to write questions or comments
or let us know you would like to say something
•Respect the pause
•Please try not to speak over the presenter or a speaker
who is voicing a question or thought
•Remember to state your name before speaking for the
note taker
•This is a public advisory meeting –presentations and
comments will be recorded and documented
3
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 387 of 794
Integrated Resource Planning
•Required by Idaho, Oregon and Washington* every other
year
•Guides resource strategy over the next twenty + years
•Current and projected load & resource position
•Resource strategies under different future policies
–Resource choices
–Conservation measures and programs
–Transmission and distribution integration for electric
–Gas distribution planning
–Gas and electric market price forecasts
•Scenarios for uncertain future events and issues
•Key dates for modeling and IRP development are
available in the Work Plans
4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 388 of 794
Technical Advisory Committee
•The public process piece of the IRP –input on what to study, how to
study, and review of assumptions and results
•Wide range of participants involved in all or parts of the process
–Ask questions
–Help with soliciting new members
•Open forum while balancing need to get through all of the topics
•Welcome requests for studies or different assumptions.
–Time or resources may limit the number or type of studies
–Earlier study requests allow us to be more accommodating
–August 1, 2020 was the electric study request deadline
•Planning teams are available by email or phone for questions or
comments between the TAC meetings
5
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 389 of 794
2020 Electric IRP Meetings – IPUC
•AVU-E-19-01 https://puc.idaho.gov/case/Details/3633
•Telephonic public hearing on August 5, 2020
•August 19, 2020 comment deadline, September 2, 2020 response
•Overview of topics discussed at July 9, 2020 virtual public workshop:
–Moving away from coal
–Cost impacts for Idaho customers from Washington laws
–IRP procedural questions about acknowledgment of the IRP
–Climate change questions and timing of actions
–Colstrip: decommissioning, other owners, cost sharing with Washington
–Consideration of social costs/externalities and public health
–Support for clean energy and Commission authority to require it
–Resource timing
–Risks considered in the IRP: economic, qualitative and climate
–Idaho versus Montana wind locations
–Maintaining Idaho RECs
–Climate change law applicability and lawsuits6
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 390 of 794
2021 Natural Gas IRP TAC Schedule
•TAC 1: Wednesday, June 17, 2020
•TAC 2: Thursday, August 6, 2020 (Joint with Electric TAC)
•TAC 3: Wednesday, September 30, 2020
•TAC 4: Wednesday, November 18, 2020
•TAC 5: February 2021 –TAC final review meeting if necessary
•Natural Gas TAC agendas, presentations and meeting minutes
available at: https://myavista.com/about-us/integrated-resource-
planning
7
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 391 of 794
2021 Electric IRP TAC Schedule
•TAC 1: Thursday, June 18, 2020
•TAC 2: Thursday, August 6, 2020 (Joint with Natural Gas TAC)
•Economic and Load Forecast, August 2020
•TAC 3: Tuesday, September 29, 2020
•TAC 4: Tuesday, November 17, 2020
•TAC 5: Thursday, January 21, 2021
•Public Outreach Meeting: February 2021
•TAC agendas, presentations and meeting minutes available at:
https://myavista.com/about-us/integrated-resource-planning
8
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 392 of 794
Process Updates
Economic and load forecast delay
•Special meeting 1:00 –3:30 pm PST on Tuesday, August 18 or
Wednesday, August 19, 2020 to cover the forecasts
AEG Conservation Potential Assessment and Demand
Response Studies –delayed from TAC 2
•AEG has developed baseline assumptions, market profiles and
energy/gas use per customer
•Market data has been collected and compiled
•Measure Assumption development is complete
•Compiled 2021 Power Plan Assumptions
•Measure List is in-process and is expected to be available mid-
September
•CPA discussion with TAC –September TAC meeting.
9
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 393 of 794
Today’s TAC Agenda
9:00 –Introductions & IRP Process Updates, Lyons
9:30 –Natural Gas & RNG Market Overview, Pardee
10:45 –Break
11:00 –Natural Gas Price Forecast, Brutocao
11:30 –Lunch
12:30 –Upstream Natural Gas Emissions, Pardee
1:30 –Break
1:45 –Regional Energy Policy Update, Lyons
2:15 –Natural Gas and Electric Coordinated Study, Gall/Pardee
3:00 –Highly Impacted & Vulnerable Populations Baseline
Analysis, Gall
3:45 –Adjourn
10
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 394 of 794
Natural Gas Market Overview
Tom Pardee, Natural Gas Planning Manager
Second Technical Advisory Committee Meeting
August 6, 2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 395 of 794
Units
Common Gas Units
1 Bcf 1 Dth 1 Therm
kWh 302,062,888 293.001 29.300
MWh 302,063 0.293 0.029
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 396 of 794
Avista Electric Territory
Avista Natural Gas Territory
Station 2
AECO
Sumas
Malin
Electric Power Plants
Northwest Pipeline
Gas Transmission NetworkKingsgate
Receipt Point
Jackson Prairie Storage (LDC Owned)
Stanfield
NGTL System
(Production and
Gathering
Systems)
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 397 of 794
Avista’s Supply
•Natural Gas LDC Side
–10% contracted from US supply basins
–90% contracted from Canadian supply basins
•Electric Side
–100% contracted from Canadian supply basins
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 398 of 794
US Demand
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040
%
o
f

D
e
m
a
n
d
% US Gas Demand
Residential Commercial Industrial Power LNG Exports Net Mexican Exports Transport Other
0
20
40
60
80
100
120
140
2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040
bc
f
d
US Gas Demand
Residential Commercial Industrial Power LNG Exports Net Mexican Exports Transport Other
Source: Wood Mackenzie2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 399 of 794
US Supply
0
20
40
60
80
100
120
140
2010 2013 2016 2019 2022 2025 2028 2031 2034 2037 2040
bc
f
d
US Gas Supply
Production Canadian Net Imports LNG Imports
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
bc
f
d
Rockies San Juan Gulf Coast Gulf of Mexico
Permian Fort Worth Northeast West Coast
Alaska Mid-Continent
Source: Wood Mackenzie2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 400 of 794
Canadian Supply and Demand
0
5
10
15
20
25
30
2010 2013 2016 2019 2022 2025 2028 2031 2034 2037 2040
bc
f
d
Canadian Gas Demand
Residential Commercial Industrial Power
LNG Exports Piped exports Transport Other
88%
90%
92%
94%
96%
98%
100%
2011 2014 2017 2020 2023 2026 2029 2032 2035 2038
bc
f
d
Canadian Supply
WCSB Eastern Canada
Source: Wood Mackenzie2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 401 of 794
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 402 of 794
-
5
10
15
20
25
30
35
Bc
f
pe
r

D
a
y
North American LNG Exports
Cove Point Elba Island Sabine Pass Cameron
Freeport Corpus Christi Golden Pass Calcasieu Pass
Kenai Woodfibre LNG LNG ELA Generic LNG ETX Generic
LNG WLA Generic Costa Azul LNG Canada LNG Western Canada Generic9
*WM does not assume Jordan Cove will enter service within forecasted period Source: Wood Mackenzie
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 403 of 794
West
2020 H1
Census Region Map
Note: Pacific does not include Alaska or Hawaii
-
2.00
4.00
6.00
8.00
10.00
12.00
14.00
16.00
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
Bc
f
pe
r

D
a
y
Total Demand by Census Region
Mountain Pacific
Source: Wood Mackenzie2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 404 of 794
-
0.05
0.10
0.15
0.20
0.25
0.30
0.35
0.40
0.45
0.50
Bc
f

p
e
r

D
a
y
Transport
Mountain Pacific
-
0.50
1.00
1.50
2.00
2.50
3.00
Bc
f
pe
r

D
a
y
Power Generation
Mountain Pacific
Power Generation and Transport demand
Source: Wood Mackenzie2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 405 of 794
-
0.20
0.40
0.60
0.80
1.00
1.20
1.40
1.60
1.80
2.00
Bc
f

p
e
r

D
a
y
Residential
Pacific Mountain
-
0.50
1.00
1.50
2.00
2.50
3.00
3.50
Bc
f

p
e
r

D
a
y
Industrial
Pacific Mountain
West demand of Res-Com-Ind
-
0.20
0.40
0.60
0.80
1.00
1.20
Bc
f

p
e
r

D
a
y
Commercial
Pacific Mountain
Port of Kalama –NW
Innovation Works
Source: Wood Mackenzie
Source: Wood Mackenzie
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 406 of 794
Wood Mackenzie Disclaimer
•The foregoing [chart/graph/table/information] was obtained from the [North America Gas Service]™, a product of Wood Mackenzie.”
•Any information disclosed pursuant to this agreement shall further include the following disclaimer: "The data and information provided by Wood Mackenzie should not be interpreted as advice and
•you should not rely on it for any purpose. You may not copy or use this data and information except as expressly permitted by Wood Mackenzie in writing. To the fullest extent permitted by law,
•Wood Mackenzie accepts no responsibility for your use of this data and information except as specified in a written agreement you have entered into with Wood Mackenzie for the provision of such of such data and information
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 407 of 794
Us Natural Gas Storage
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 408 of 794
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
#
o
f

R
i
g
s
US Rig Count History
Oil Gas Misc15
0
100
200
300
400
500
600
700
#
o
f

R
i
g
s
Canadian Rig Count History
OIL GAS MISC
Rig Counts
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 409 of 794
Production and Drilling efficiency
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 410 of 794
Historic Cash prices
(Jan. 1997 –July 2020)
$0.00
$2.00
$4.00
$6.00
$8.00
$10.00
$12.00
$14.00
$16.00
$18.00
$20.00
$
p
e
r

M
M
B
t
u
17
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 411 of 794
Upstream Emissions
Tom Pardee
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 412 of 794
Upstream Emissions
•Use based greenhouse gas emissions at the point of combustion
and include upstream methane emissions
•Link for Natural Gas Advisory Committee information on upstream
methane: https://www.nwcouncil.org/energy/energy-advisory-
committees/natural-gas-advisory-committee
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 413 of 794
Global warming potential (GWP) factors for conversion
to CO2 equivalents (CO2e)
5th Assessment of the Intergovernmental Panel on Climate Change
Greenhouse Gas GWP –100 Year GWP –20 Year
CO2 1 1
CH4 34 86
N2O 298 268
https://www.c2es.org/content/ipcc-fifth-assessment-report/
Global Warming Potential
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 414 of 794
Upstream Emissions Sources and Estimates
•Rockies emissions –The EPA estimates all leakage through a bottoms up
analysis. It will estimate leaks based on equipment operated as designed
and combines these values to determine an overall rate of 1%. The
emissions and sinks study is published yearly and will capture emissions as
they change.
•Canadian emissions (British Columbia and Alberta) –A value of 0.77% was
developed from data pertaining to the recent environmental impact studies
for the PSE Tacoma LNG plant, Kalama Manufacturing and Export Facility
and the 2019 Puget Sound Energy IRP.
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 415 of 794
WSU Natural Gas Methane Study
•Sponsored by EDF and utilities to estimate the leakage of
distribution systems
•National project and estimated a loss of 0.1 –0.2 percent of the
methane delivered nationwide
•Western region contributes much less as compared to the East
•“Out of 230 measurements, three large leaks accounted for
50%of the total measured emissions from pipeline leaks. In these
types of emission studies, a few leaks accounting for a large
fraction of total emissions are not unusual.”
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 416 of 794
LDC Upstream Emissions
*Avista gas purchases
An average of the total volume purchased over the past 5
years by emissions location2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 417 of 794
Electric Upstream Emissions
*Avista Purchases
All firm transportation to supply gas is located in Canada2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 418 of 794
Renewable Natural Gas (RNG)
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 419 of 794
What is Renewable Natural Gas (RNG)?
Renewable Natural Gas
= Natural
Gas
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 420 of 794
Why does RNG matter?
Climate Change Solution
•Natural gas plays critical role for meeting aggressive green house gas
(GHG) reductions goals, RNG even more so!
•Utilizes existing infrastructure
•Advantages of RNG
–“De-carbonizes” gas stream
–Gives customers another renewable choice
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 421 of 794
Carbon Intensity
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 422 of 794
RFS and LCFS Effect on RNG Value
RIN = renewable identification number
Source: CARB
Source: EPA2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 423 of 794
What are the challenges & barriers?
•California RNG market ($30+/Dth v. $2/Dth)
–Vehicle emission incentives shut-out other potential end users
–Producers see the pot of gold in California
•Financing for producers
–RIN market is volatile
–No forward pricing for RNG RINs in carbon market
–Vehicle market may be approaching saturation in CA
–Producer/LDC partnerships may make sense
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 424 of 794
WA RNG Report (HB 2580)
*Released December 1, 2018
WSU Energy Program, Harnessing Renewable Natural Gas for Low-Carbon Fuel: A Roadmap for Washington State
0
500,000
1,000,000
1,500,000
2,000,000
2,500,000
Cedar Hills
Landfill (King
County)
Roosevelt
Landfill
(Republic
Services)
KlickitatCounty PUD
South
Treatment
Plant (King
County)
Puget SoundEnergy
Landfills Wastewater
treatment
plants
Dairy
digesters
Municipal
food waste
digesters
Food
processing
residuals
Food
processed at
compost
facilities
Landfills Wastewater
treatment
plants
Dairy
digesters
Municipal
food waste
digesters
Dth
Existing Projects
Near Term Projects
Medium Term Projects
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 425 of 794
Total Potential Annual Production = 32 Bcf
ID RNG NREL Estimates
Source -Anaerobic MMBtu per Year
Landfills 3,712,221
6,196,531
20,220,571
-Separated Organics (Solid Waste)2,311,354
Total 32,440,676
National Renewable Energy Laboratory, NREL Biofuels Atlas
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 426 of 794
RNG $ per Dth/MMBtu
Source: Promoting RNG in WA State
Avista Owned and Operated
ID -WA
2035 Premium
Estimate ($ / Dth)
RNG -Landfills $7 -$10
RNG -Waste Water Treatment Plants (WWTP)$12 -$22
RNG -Agriculture Manure $28 -$53
RNG -Food Waste $29 -$53
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 427 of 794
Natural Gas IRP
A detailed level of RNG understanding and evaluation process will
be included in the Natural Gas IRP TAC #3 meeting on September
30, 2020
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 428 of 794
Natural Gas Price Forecast
Michael Brutocao, Natural Gas Analyst
Second Technical Advisory Committee Meeting
August 6, 2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 429 of 794
Henry Hub Expected Price Methodology
•Expected Henry Hub prices derived from a blend of forward
market prices on the NYMEX (as of 6/30/2020) and forecasted
prices from the 2020 Annual Energy Outlook (EIA) and two
consultants
2020 – 2022 2023 2024 2025 2026 – 2045
NYMEX 100%75%50%25%-
EIA/AEO -8.33%16.66%25%33.33%
Consultant 1 -8.33%16.66%25%33.33%
Consultant 2 -8.33%16.66%25%33.33%
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 430 of 794
Henry Hub Expected Price and Forecast Blending
3
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 431 of 794
Henry Hub Expected Price and Average Annual Forecasts
4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 432 of 794
Stochastic Price Forecasting Methodology
•Evaluate a set of potential future outcomes based on the
probability of occurrence
–Expected Price used as the input
–At each period, random price adjustments follow a lognormal distribution
based on the Expected Price
•It is common practice to use lognormal distributions in forecasting prices as they have
no upward bound and should not fall below zero
•A single “draw” contains a set of unique price movements
•500 (electric) and 1000 (gas) draws were evaluated
5
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 433 of 794
Sample Stochastic Price Draws
6
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 434 of 794
Stochastic Price Draws
7
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 435 of 794
Stochastic Prices (Results from 500 Draws)
8
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 436 of 794
Levelized Stochastic Prices (Results from 500 Draws)
9
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 437 of 794
Stochastic Prices (Results from 1000 Draws)
10
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 438 of 794
Levelized Stochastic Prices (Results from 1000 Draws)
11
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 439 of 794
Prices by Gas Hub (Henry Hub Expected Price + Basis)
12
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 440 of 794
Levelized Prices 2022-2041
13
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 441 of 794
Levelized Prices 2022-2045
14
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 442 of 794
2021 Electric IRP
Regional Energy Policy Update
John Lyons, Ph.D.
Second Technical Advisory Committee Meeting
August 6, 2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 443 of 794
Production and Investment Tax Credits
•Production tax credit $15/MWh adjusted for inflation
($25/MWh for 2019) for 10 years for wind construction
started by 12/31/20
•Investment tax credit for new solar construction drops
from 30% in 2019
–26% in 2020
–22% in 2021
–10% from 2022 onward
•Will be watching for any possible extensions with all of
the COVID-19 proposals
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 444 of 794
State and Provincial Policies
State/Province No Coal RPS Clean Energy/Carbon Goal
Alberta Yes Yes Yes
Arizona No Yes No
British Columbia Yes Yes Yes
California Yes Yes Yes
Colorado No Yes Yes
Idaho No No No
Montana No Yes No
Nevada No Yes Goal
New Mexico No Yes No
Oregon Yes Yes Yes
Utah No Goal No
Washington Yes Yes Yes
Wyoming No No No
3
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 445 of 794
Washington
•Clean Energy Transformation Act (CETA) SB 5116:
–No coal serving Washington customers by end of 2025
–Greenhouse gas neutral by 2030, up to 20% alternative
compliance
–2% cost cap over four-year compliance period
–100% non-emitting by January 1, 2045
–Social cost of carbon for new resources
–Additional reporting and planning requirements
–Highly impacted and vulnerable community identification
and resource planning implications
–Ongoing rulemaking in various stages for planning and
reporting
4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 446 of 794
Washington
•HB 1257: Clean Buildings for Washington Act
–Develop energy performance standards for commercial buildings over
50,000 square feet (2020 –2028) “… to maximize reductions of
greenhouse gas emissions from the building sector”
–By 2022, natural gas utilities must identify and acquire all available cost-
effective conservation including a social cost of carbon at the 2.5%
discount rate.(Section 11 and 15)
–Natural gas utilities may propose renewable natural gas (RNG)
programs for their customers and offer a voluntary RNG tariff
–Building code updates to improve efficiency and develop electric vehicle
charging infrastructure
5
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 447 of 794
Oregon
Executive Order 20-04
•New GHG reduction goal
–45% below 1990 levels by 2035
–80% below 1990 levels by 2050
•Directs 16 Oregon agencies to “exercise any and all authority
and discretion” to reach GHG reduction goals and “prioritize
and expedite” action on GHG reductions “to the full extent
allowed by law.”
•Agencies are working on rulemaking and implementation
SB 98
•Development of utility renewable natural gas programs
6
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 448 of 794
2021 Electric and Natural Gas IRPs
Natural Gas & Electric Coordinated Scenario
James Gall/Tom Pardee
Second Technical Advisory Committee Meeting
August 6, 2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 449 of 794
Scenario Goal
•Understand impact to electric resource planning if
customers switch from natural gas to electric service
•Scenario Proposal:
–By 2030: 50% of Washington Residential & Commercial
customers
–By 2045: 80% of Washington Residential & Commercial
customers
•Potential Scenarios:
–Hybrid natural gas/electric heat pumps
–Highly efficient technology allows for cold temperature space
heating
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 450 of 794
Converting Natural Gas Load to Electric
Load
Natural Gas
(therms)TemperatureEnd Use Efficiency
Electric
Service Provider
Electric
(kWh)
3
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 451 of 794
WA Res/Com Natural Gas Load Forecast
4
MD
t
h
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 452 of 794
Customer Penetration Forecast
0.0%
10.0%
20.0%
30.0%
40.0%
50.0%
60.0%
70.0%
80.0%
90.0%
20
2
0
20
2
0
20
2
1
20
2
1
20
2
2
20
2
2
20
2
3
20
2
3
20
2
4
20
2
4
20
2
5
20
2
5
20
2
6
20
2
6
20
2
7
20
2
7
20
2
8
20
2
8
20
2
9
20
2
9
20
3
0
20
3
0
20
3
1
20
3
1
20
3
2
20
3
2
20
3
3
20
3
3
20
3
4
20
3
4
20
3
5
20
3
5
20
3
6
20
3
6
20
3
7
20
3
7
20
3
8
20
3
8
20
3
9
20
3
9
20
4
0
20
4
0
20
4
1
20
4
1
20
4
2
20
4
2
20
4
3
20
4
3
20
4
4
20
4
4
20
4
5
20
4
5
% Natural Gas Customer Reduction (WA Only)
5
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 453 of 794
End Use Efficiency
0%
20%
40%
60%
80%
100%
120%
140%
160%
Water Heat Space Heat Process
Efficiency @ 5 Degrees
0%
20%
40%
60%
80%
100%
120%
140%
160%
Water Heat Space Heat Process
Efficiency @ 35 Degrees
Water Heat, 10.0%
Space Heat, 85.0%
Process, 5.0%
Water Heat, 30.0%
Space Heat, 60.0%
Process, 10.0%
Note: All efficiency conversion use a 10% efficiency benefit to electric
6
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 454 of 794
Energy Conversion Factor
y = -3E-06x4 + 0.0007x3 -0.0438x2 -0.7097x + 259.49
R² = 0.9775
0
50
100
150
200
250
300
-20 0 20 40 60 80 100
Use
temperature
point
estimates
for
conversion
efficiency
Curve fit to
smooth out
steps
7
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 455 of 794
WA Res/Com Natural Gas Load Forecast
8
MD
t
h
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 456 of 794
Electric Peak Estimation Methodology
•Natural gas is typically daily nominations, while electric is
instantaneous.
–Hourly flow metering is available for some areas
•Sampled large gate-station hourly instantaneous natural
gas flow data
•Use sample data to estimate hourly natural gas load
from 2015-2019
•Estimate Peak-to-Energy load factor for each historical
month
•Use average monthly load factor for the peak adjustment
9
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 457 of 794
Estimated Load Factors (2015-19)
10
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 458 of 794
Hourly Electric Load History
-
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
5,000
Me
g
a
w
a
t
t
s
2015-2019 Control Area Load + WA LDC as Electric
CA Load + NG Control Area Load
11
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 459 of 794
Eastern Washington Electric Service
Providers
EIA reported retail sales for 2018
Scenario assumes Avista will receive 75 percent of electric conversions
12
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 460 of 794
Annual Conversion Load Forecast
-
100
200
300
400
500
600
700
800
900
1,000
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Annual Avg Peak
13
2020 IRP Forecast for 2030 absent fuel conversion:
Peak: 1,762 MW
Energy: 1,209 aMW
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 461 of 794
2030 Monthly Load Forecast
-
50
100
150
200
250
300
350
400
450
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Energy Peak
14
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 462 of 794
Scenario Analysis-Conversion Rates
0
50
100
150
200
250
300
-20 0 20 40 60 80 100
Current Technology
Hybrid Future
High Efficiency Future
15
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 463 of 794
Scenario Analysis- Electric Energy
16
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 464 of 794
Scenario Analysis: Electric December
Peak Load
17
Me
g
a
w
a
t
t
s
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 465 of 794
Scenario Analysis: Natural Gas Demand
18
MD
t
h
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 466 of 794
Next Steps
•Input into PRiSM model to determine resource
selection and cost
–Estimate cost meeting CETA requirements
–Estimate cost using least cost methodology
–Estimate emissions savings
–Estimate $/tonne
•Conduct electric resource adequacy study if time
permits
19
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 467 of 794
2021 Electric IRP
Washington Vulnerable Populations &
Highly Impacted Communities
James Gall, IRP Manager
Second Technical Advisory Committee Meeting
August 6, 2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 468 of 794
Identifying Communities or “Customers”
Highly Impacted
Communities
–Cumulative Impact Analysis
–Tribal lands
•Spokane
•Colville
–Locations should be available
by end of 2020
•State held workshops in
August & September 2019
Vulnerable
Populations
–Use Washington State Health
Disparities map
•What is disproportionate on a
scale of 1 to 10?
•Avista proposes areas with a
score 8 or higher in either
Socioeconomic factors or
Sensitive population metrics
–Should we include other
metrics to identify these
communities?
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 469 of 794
Environmental Health Disparities Map
https://fortress.wa.gov/doh/wtn/wtnibl/
Department of Health data is divided up by Federal Information Processing Standards (FIPS) Code
3
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 470 of 794
Environmental Health Scoring
From WA Department of Health
Circle areas match definition of
vulnerable population,
although access to food &
health care, higher rates of
hospitalization are not
expressively included but are
an indication of poverty
4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 471 of 794
Selected Vulnerable Populations
5
Data is shown
by combined
score
Natural Gas
Biomass
Hydro
Wind
Solar
Kettle Falls CT
Kettle Falls
Little Falls Long Lake
Nine Mile
Palouse
Rattlesnake Flat
Adams Neilson
Northeast
Boulder ParkMonroe St
Upper Falls
Post Falls
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 472 of 794
Spokane Area “Avista” Vulnerable
Populations
6
Data is shown
by combined
score
Natural Gas
Biomass/Other
Hydro
Wind
Solar
Waste-to-Energy (QF)
Upriver (QF)Boulder Park
BP Community Solar
Northeast
Monroe Street
Upper Falls
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 473 of 794
IRP Metrics (From Last TAC Meeting)
Metric IRP Relationship
Energy Usage per Customer •Expected change taking into account selected energy
efficiency then compare to remaining population.
•EE includes low income programs and TRC based
analysis which includes non-economic benefits.
Cost per Customer •Estimate cost per customer then compare to
remaining population.
•How do IRP results compare to above 6% of income?
Preference •Should the IRP have a monetary preference?
•For example-should all customers pay more to
locate assets (or programs) in areas with
vulnerable populations or highly impacted
communities?
•If so, how much more?
7
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 474 of 794
IRP Metrics (From Last TAC Meeting)
Metric IRP Relationship
Reliability
•SAIFI: System Average Interruption
Frequency Index
•MAIFI: Momentary Average Interruption
Frequency Index
•Calculate baseline for each distribution feeder and
match with communities
•Estimate benefits for area with potential IRP
distribution projects
•Compare to other communities as baseline
•May be more appropriate in Distribution plan rather
than IRP
Resiliency:
•SAIDI: System Average Interruption Duration
Index
•CAIDI: Customer Average Interruption
Duration Index
•CELID: Customer’s Experiencing Long
Duration Outages
Resource Analysis •Estimate emissions (NOX,SO2, PM2.5, Hg) from
power projects located in/near identified communities
•Identify new resource or infrastructure project
candidates with benefit to communities; i.e. economic
benefit, reliability benefit
•Identify how resource can benefit energy security
8
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 475 of 794
Energy Use Analysis Results
•Uses five years of customer billing data
•Median income over the same period is used to estimate
affordability
•Separated electric only vs electric/gas customers
–Future enhancement include single/multi family homes, and
manufactured homes
9
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 476 of 794
Energy/Cost Analysis
Electric Only Customers
Natural Gas/Electric Customers
Note: Combined natural gas/electric homes have higher energy burden due to
fewer multifamily homes included in the population or all electric home including
homes with alternative heat such as wood, propane, oil, pellets. Future analysis
needed to validate this hypothesis.10
Area Fuel Type Energy Use Avg Bill Income % Income
Vulnerable Population Areas Electric 820 KWh $80
Other Areas Electric 875 KWh $84
Vulnerable Population Areas Gas 52 Therms $47 $44,889 3.4%
Other Areas Gas 62 Therms $56 $68,250 2.5%
Area Fuel Type Energy Use Avg Bill Income % Income
Vulnerable Population Areas Electric 998 KWh $98 $42,730 2.8%
Other Areas Electric 1,010 KWh $100 $58,834 2.0%
Note: Mean energy use is statistically significantly different when removing energy use data below 100 kWh per month (1,049 kWh vs 1,082 kWh)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 477 of 794
Vulnerable Populations
Electric Only Customers-Energy % of Income
11
Spokane Area
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 478 of 794
Vulnerable Populations
Gas/Electric Only Customers-Energy % of Income
12
Spokane Area
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 479 of 794
Reliability Data- CAIDI
Measure of resilience-minutes of outages per event
Excludes Major Event Days (MED)
13
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 480 of 794
Reliability Data-CEMI
Measure of reliability-Events per Customer
14
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 481 of 794
Vulnerable Area vs Non Vulnerable Areas
Vulnerable Areas
Non-Vulnerable Areas
CAIDI CEMI
15 Note: 5 yr Average differences are statistically significantly different
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 482 of 794
CAIDI- By Feeder Type
Note: Avista has no
vulnerable areas with urban feeders
16
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 483 of 794
CEMI- By Feeder Type
Mixed Feeders
Vulnerable Areas
Non-Vulnerable Areas
Rural Feeders
Vulnerable Areas
Non-Vulnerable Areas
Note: Avista has no
vulnerable areas with urban feeders
17 0.0
1.0
2.0
3.0
4.0
5.0
2015 2016 2017 2018 2019 5 yr Avg
Ev
e
n
t
s
Suburban Feeders
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 484 of 794
Avista’s Washington Power Plant Air
Emissions
-
0.5
1.0
1.5
2.0
2.5
3.0
2015 2016 2017 2018 2019
Washington NOx Emissions
-
0.005
0.010
0.015
0.020
0.025
0.030
2015 2016 2017 2018 2019
Washington SO2 Emissions
-
0.00001
0.00001
0.00002
0.00002
0.00003
0.00003
0.00004
0.00004
0.00005
0.00005
2015 2016 2017 2018 2019
Washington Hg Emissions
-
0.050
0.100
0.150
0.200
0.250
0.300
2015 2016 2017 2018 2019
Washington VOC Emissions
18
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 485 of 794
TAC Input
•What other metrics can we provide in an IRP to
show vulnerable populations and highly
impacted communities are not harmed by the
transition to clean energy
19
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 486 of 794
Economic, Load, and Customer Forecasts
Grant D. Forsyth, Ph.D.
Chief Economist
Technical Advisory Committee Meeting
August 18, 2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 487 of 794
Main Topic Areas
•Service Area Economy
•Long-run Energy Forecast
•Peak Load Forecast
•Long-run Gas Customer Forecast
2
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 488 of 794
Service Area Economy
Grant D. Forsyth, Ph.D.
Chief Economist
[e-mail]
3
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 489 of 794
Distribution of Employment, 2019
Source: BLS and author’s calculations.4
Private
Goods
14%
Private
Services
70%
Government
16%
Avista WA-ID-OR MSA
Private
Goods
14%
Private
Services
71%
Government
15%
U.S.
Federal
11%
State
20%
Local
69%
Avista WA-ID-OR MSA Government
Federal
12%
State
23%
Local
65%
U.S. Government
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 490 of 794
Non-Farm Employment Growth, 2009-2020
Source: BLS, WA ESD, OR ED and author’s calculations.5
-16%
-14%
-12%
-10%
-8%
-6%
-4%
-2%
0%
2%
4%
De
c
-
0
7
Ap
r
-
0
8
Au
g
-
0
8
De
c
-
0
8
Ap
r
-
0
9
Au
g
-
0
9
De
c
-
0
9
Ap
r
-
1
0
Au
g
-
1
0
De
c
-
1
0
Ap
r
-
1
1
Au
g
-
1
1
De
c
-
1
1
Ap
r
-
1
2
Au
g
-
1
2
De
c
-
1
2
Ap
r
-
1
3
Au
g
-
1
3
De
c
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1
3
Ap
r
-
1
4
Au
g
-
1
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1
4
Ap
r
-
1
5
Au
g
-
1
5
De
c
-
1
5
Ap
r
-
1
6
Au
g
-
1
6
De
c
-
1
6
Ap
r
-
1
7
Au
g
-
1
7
De
c
-
1
7
Ap
r
-
1
8
Au
g
-
1
8
De
c
-
1
8
Ap
r
-
1
9
Au
g
-
1
9
De
c
-
1
9
Ap
r
-
2
0
Ye
a
r
-ov
e
r
-Ye
a
r
,

S
a
m
e

M
o
n
t
h

S
e
a
s
o
n
a
l
l
y

A
d
j
.
Non-Farm Employment Growth (Dashed Shaded Box = Recession Period)
Avista WA-ID-OR MSAs U.S.
Service Area employment level
same as 2013/14 period.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 491 of 794
MSA Population Growth, 2007-2019
Source: BEA, U.S. Census, and author’s calculations.6
1.6%
1.2%
0.9%
0.7%
0.5%0.4%
0.7%
1.0%
1.2%
1.6%1.6%
1.5%1.5%
1.0%0.9%0.9%0.8%
0.7%0.7%0.7%0.7%0.7%0.7%0.6%0.5%0.5%
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
An
n
u
a
l

G
r
o
w
t
h
Population Growth in Avista WA-ID-OR MSAs
Total WA-ID-OR MSA Pop. Growth U.S. Growth
2008-2012: Employment
Growth Slowing = Slowing
In-migration
2013-2019: Employment
Growth Increasing =
Increasing In-migration
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 492 of 794
GDP Growth Assumptions: 2021 IRP vs. 2020 IRP
7 Source: Various and author’s calculations.
-8.0%
-6.0%
-4.0%
-2.0%
0.0%
2.0%
4.0%
6.0%
2020 2021 2022 2023 2024 2025
An
n
u
a
l

G
r
o
w
t
h
Average June 2019 Forecast Current Forecast Average
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 493 of 794
Long-Term Energy Load Forecast
Grant D. Forsyth, Ph.D.
Chief Economist
[e-mail]
8
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 494 of 794
Basic Forecast Approach
2020
Time
2025 20452026
1)Monthly econometric model by
schedule for each class.
2)Customer and UPC forecasts.
3)20-year moving average for “normal
weather.”
4)Economic drivers: GDP, industrial
production, employment growth,
population, price, natural gas
penetration, and ARIMA error
correction.
5)Native load (energy) forecast derived
from retail load forecast.
6)Current forecast is the “Summer/Fall
Forecast” done in June.
1)Boot strap off medium term forecast.
2)Apply long-run load growth relationships to
develop simulation model for high/low
scenarios.
3)Include different scenarios for renewable
penetration with controls for price elasticity,
EV/PHEVs, and natural gas penetration.
Medium Term Long Term
9
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 495 of 794
The Long-Term Relationship, 2021-2045
Load = Customers Χ Use Per Customer (UPC)
Load Growth ≈ Customer Growth + UPC Growth
Assumed to be same as population
growth for residential after 2025,
commercial growth will follow
residential, and slow decline in
industrial.
Assumed to be a function of
multiple factors including
renewable penetration, gas
penetration, and
EVs/PHEVs.
10
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 496 of 794
Residential Customer Growth, 2020-2045
0.40%
0.50%
0.60%
0.70%
0.80%
0.90%
1.00%
1.10%
1.20%
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Annual Residential Customer Growth Rates
2021 IRP Residential Customer Growth 2020 IRP Residential Customer Growth
Medium Term Long Term
Average annual growth rate from
2021-2045 = 0.8%. Shape of
time-path mimics a combination
of IHS (ID) and OFM (WA)
population forecasts.
11
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 497 of 794
Residential Solar Penetration, 2008-2019
0.00%
0.05%
0.10%
0.15%
0.20%
0.25%
0.30%
0.35%
305,000 310,000 315,000 320,000 325,000 330,000 335,000 340,000 345,000 350,000
Sh
a
r
e

o
f

R
e
s
i
d
e
n
t
i
a
l

S
o
l
a
r

C
u
s
t
o
m
e
r
s

t
o

T
o
t
a
l

R
e
s
i
d
e
n
t
i
a
l

Cu
s
t
o
m
e
r
s
Customers
Customer Penetration vs. Customers Since 2008
12
2014
2015
2016
2017
2018
2008
2019
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 498 of 794
Residential Solar Penetration, 2021-2045
0
2,000
4,000
6,000
8,000
10,000
12,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
To
t
a
l

P
V

C
u
s
t
o
m
e
r
s
Projected Base-Line Residental Solar Customers
2021 IRP Base-Line Residential Solar Customers 2020 IRP Base-Line Residential Solar Customers13
Current penetration is 0.3% and typical
size is 7,800 watts. By 2045, penetration
will be near 2.6% of residential customers
and average size of installed systems will
be over 10,000 watts.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 499 of 794
Residential EVs/PHEVs, 2021-2045
0
20,000
40,000
60,000
80,000
100,000
120,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
To
t
a
l

E
V
s
/
P
H
E
V
s
Projected Residental EVs/PHEVs
2020 IRP Projected EV/PHEV 2021 IRP Projected EV/PHEV
2020 ≈ 2,000
14
2045 ≈ 107,000
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 500 of 794
Net Solar and EV/PHEV Impact, 2021-2045
-5
0
5
10
15
20
25
30
35
40
45
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Average Megawatt Impact of Solar and EV/PHEV
2021 IRP Solar aMW (Load Reduction)2021 IRP EV/PHEV aMW (Load Addition)2021 Net IRP Solar and EV/PHEV Impacts aMW15
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 501 of 794
Native Load Forecast, 2021-2045
1,000
1,050
1,100
1,150
1,200
1,250
1,300
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Total Native Load Forecast, Average Megawatts
2021 IRP Base-Line Native Load 2020 IRP Base-Line Native Load
EV/PHEV “Bend”
IRP Avg. Annual
Growth
2020 IRP 0.3%
2021 IRP 0.3%
Medium Term Long Term
16
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 502 of 794
Climate Change: A Trended 20-year Moving
Average (Preliminary!)
17
5,000
5,500
6,000
6,500
7,000
7,500
1965 1969 1973 1977 1981 1985 1989 1993 1997 2001 2005 2009 2013 2017 2021 2025 2029 2033 2037 2041 2045
HD
D
20-yr MA HDD
Annual 20-yr MA, Avista Trend Annual 20-yr MA, NWCC Trend Current 20-yr MA
0
100
200
300
400
500
600
700
800
1965 1969 1973 1977 1981 1985 1989 1993 1997 2001 2005 2009 2013 2017 2021 2025 2029 2033 2037 2041 2045
CD
D
20-yr MA CDD
Annual 20-yr MA, Avista Trend Annual 20-yr MA, NWCC Trend Current 20-yr MA
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 503 of 794
Annual Native Load Forecast with Climate
Change, 2026-2045 (Preliminary!)
1,090
1,100
1,110
1,120
1,130
1,140
1,150
1,160
1,170
2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
2021 IRP Base-Line Native Load 2021 IRP Base-Line Native Load, Avista Trend 2021 IRP Base-Line Native Load, NWCC Trend18
IRP Avg. Annual Growth
2021 IRP, No Trend Base-Line 0.23%
2021 IRP, NWCC Trend 0.13%
2021 IRP, Avista Trend 0.21%
0.3% Lower than
Non-Trend Base-
Line
2% Lower than
Non-Trend Base-
Line
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 504 of 794
Native Load Growth Forecast, 2021-2045
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
An
n
u
a
l

G
r
o
w
t
h
Native Load Growth
2021 IRP Base-Line Native Load Growth 2020 IRP Base-Line Native Load Growth19
EV/PHEV “Bend”
Load Recovery from
Recession
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 505 of 794
Residential UPC Growth: 2021-2045
20
-1.5%
-1.0%
-0.5%
0.0%
0.5%
1.0%
1.5%
2.0%
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Base-Line Scenario: Residential UPC Growth Rate
EIA Refrence Case Use Per Household Growth 2021 IRP Residential Base-Line UPC Growth
Source Avg. Annual
Growth
2021 IRP -0.24%
EIA 0.03%
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 506 of 794
Long-Run Load Forecast: Conservation
Adjustment
Grant D. Forsyth, Ph.D.
Chief Economist
[e-mail]
21
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 507 of 794
Comparison of Native Load Forecasts, 2021-2045
900
1,000
1,100
1,200
1,300
1,400
1,500
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Average Megawatts Load Comparision with Conservation Adjustment
Base-Line Native Load Base-Line Native Load with Conservation Added Back
22
Source Avg. Annual
Growth
2021 IRP 0.3%
No Conservation 1.0%
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 508 of 794
Peak Load Forecast
Grant D. Forsyth, Ph.D.
Chief Economist
[e-mail]
23
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 509 of 794
The Basic Model
•Monthly time-series regression model that initially excludes certain industrial loads and
EVs (but those are added back in for the final forecast).
•Based on monthly peak MW loads since 2004. The peak is pulled from hourly load data for
each day for each month.
•Explanatory variables include HDD-CDD and monthly and day-of-week dummy variables.
The level of real U.S. GDP is the primary economic driver in the model—the higher GDP, the
higher peak loads. Model allows GDP impact to differ between winter and summer.
•The coefficients of the model are used to generate a distribution of peak loads by month
based on historical max/min temperatures since 1890, holding GDP constant. A starting
expected peak load is then calculated using the average peak load simulated for that
month going back to 1890. Model shows Avista is a winter peaking utility for the forecast
period; however, the summer peak is growing at a faster than the winter peak.
•For comparison in the 2021 IRP, peak load is also calculated by averaging simulated peak
loads over the last 30 years and 20 years.
•The model is also used to calculate the long-run growth rate of peak loads for summer and
winter using a forecast of GDP growth under the “ceteris paribus” assumption for weather
and other factors.
24
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 510 of 794
Peak Forecasts for Winter and Summer, 2021-2045
1,100
1,200
1,300
1,400
1,500
1,600
1,700
1,800
1,900
2,000
19
9
7
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
20
1
3
20
1
5
20
1
7
20
1
9
20
2
1
20
2
3
20
2
5
20
2
7
20
2
9
20
3
1
20
3
3
20
3
5
20
3
7
20
3
9
20
4
1
20
4
3
20
4
5
Me
g
a
w
a
t
t
s
Winter Peak Summer Peak
Peak Avg. Growth 2021-45
Winter 0.37%
Summer 0.44%
25
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 511 of 794
Load Forecasts for Winter Peak, 2011-2043
1,500
1,750
2,000
2,250
2,500
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Me
g
a
w
a
t
t
s
Winter Peak Forecast: Current and Past
2009 IRP 2011 IRP 2013 IRP 2015 IRP 2017 IRP 2020 IRP 2021 IRP
26
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 512 of 794
Load Forecasts for Summer Peak, 2011-2045
1,500
1,750
2,000
2,250
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Me
g
a
w
a
t
t
s
Summer Peak Forecast: Current and Past
2009 IRP 2011 IRP 2013 IRP 2015 IRP 2017 IRP 2020 IRP 2021 IRP27
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 513 of 794
Peak Forecasts for Winter and Summer 30-Year
Average Weather, 2021-2045
1,100
1,200
1,300
1,400
1,500
1,600
1,700
1,800
1,900
2,000
19
9
7
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
20
1
3
20
1
5
20
1
7
20
1
9
20
2
1
20
2
3
20
2
5
20
2
7
20
2
9
20
3
1
20
3
3
20
3
5
20
3
7
20
3
9
20
4
1
20
4
3
20
4
5
Me
g
a
w
a
t
t
s
Winter Peak Summer Peak28
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 514 of 794
Peak Forecasts for Winter and Summer 20-Year
Average Weather, 2021-2045
1,100
1,200
1,300
1,400
1,500
1,600
1,700
1,800
1,900
2,000
19
9
7
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
20
1
3
20
1
5
20
1
7
20
1
9
20
2
1
20
2
3
20
2
5
20
2
7
20
2
9
20
3
1
20
3
3
20
3
5
20
3
7
20
3
9
20
4
1
20
4
3
20
4
5
Me
g
a
w
a
t
t
s
Winter Peak Summer Peak29
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 515 of 794
Long-Run Customer Forecast: Natural
Gas
Grant D. Forsyth, Ph.D.
Chief Economist
[e-mail]
30
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 516 of 794
Firm Customers (Meters) by State and Class, 2019
31
WA
47%
ID
24%
OR
29%
Firm Customers by State
Residential
90%
Commercial
10%
Industrial
0.1%
Firm Customers by Class
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 517 of 794
System All Types of Industrial Customers, 1997-2020
200
210
220
230
240
250
260
270
280
290
300
0
5
10
15
20
25
30
35
19
9
7
19
9
8
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0

E
s
t
WA
-ID

F
i
r
m

I
n
d
u
s
t
r
i
a
l
OR

F
i
r
m

I
n
d
u
s
t
r
i
a
l
OR Firm Industrial WA-ID Firm Industrial32
291 31
216
24
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 518 of 794
Customer Forecast Models
•Forecast models are structured around each schedule, in each class, by jurisdiction.
In the case of OR, this is done individually for each of Avista’s service islands.
•Time series transfer function models (models with regressions drivers and ARIMA
error terms).
•Simple time series smoothing models (for schedules with little customer variation).
•Same models used for the bi-annual revenue model forecast pushed out to 2045.
The forecasts for this IRP were generated from the “Summer/Fall 2020” forecast
completed in June.
•Customer forecasts are sent to Gas Supply for inclusion in the SENDOUT model.
•Example of transfer function model: WA sch. 101 residential customers…
33
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 519 of 794
Transfer Function Model Example
34
𝐶𝑡,𝑦,𝑊𝐴101.𝑟=𝛼0 +𝜏𝑃𝑂𝑃𝑡,𝑦,𝑆𝑃𝐾+𝝎𝑺𝑫𝑫𝒕,𝒚+𝜔𝑂𝐿𝐷𝑂𝑐𝑡2015=1 +𝜔𝑂𝐿𝐷𝐹𝑒𝑏2016=1
+𝜔𝑂𝐿𝐷𝑀𝑎𝑟2018=1 +𝜔𝑂𝐿𝐷𝑁𝑜𝑣2018=1 +𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦12,1,0 0,0,0 12
Monthly
Customer
(Meter Count)
Monthly
Interpolated
Population for
Spokane MSA
Seasonal
Dummies
Outlier
Dummies
(Interventions)
Error Correction
Component
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 520 of 794
Getting to Population as a Driver, 2020-2025 & 2026-2045
Average GDP Growth
Forecasts:
•WSJ, FOMC,
Bloomberg, etc.
•Average forecasts
out 5 full calendar
years.
Non-farm Employment
Growth Model:
•Model links year y, y-1, and
y-2 GDP growth to year y
regional employment
growth.
•Forecast out 5 full calendar
years.
•Averaged with IHS
employment growth
forecasts.
Regional Population Growth Models:
•Model links regional, U.S., and CA
year y-1 employment growth to year y
county population growth.
•Forecast out 5 full calendar years for
Spokane, WA; Kootenai, ID; and
Jackson+Josephine, OR.
•Averaged with IHS growth forecasts.
•Growth rates used to generate
population forecasts for use in
regression models—important driver
for main residential and commercial
schedules.
EMPGDP
2020-2025 For Spokane, WA; Kootenai, ID, and
Jackson+Josephine, OR
OR Douglas, Klamath, and Union counties: IHS population growth forecasts for 2020-2045
Kootenai and Jackson: IHS population growth forecasts for 2026-2045
Spokane: OFM population growth forecasts for 2026-2045
Monlthly Interpolation assumes: PN = P0erN
Deviation in the most
recent forecast!
35
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 521 of 794
WA-ID Region Firm Customers, 2021-2040 (2018 IRP)
220,000
240,000
260,000
280,000
300,000
320,000
340,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
WA-ID Base-line 2018 WA-ID Base-line 2021
IRP Avg.Annual Growth
2021-2040
2021 1.1%
2018 1.2%
≈ +1,400
36
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 522 of 794
OR Region Firm Customers, 2021-2040 (2018 IRP)
95,000
100,000
105,000
110,000
115,000
120,000
125,000
130,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
OR Base-line 2018 OR Base-line 2021
≈ -2,800
IRP Avg.Annual Growth
2021-2040
2021 0.8%
2018 0.9%
37
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 523 of 794
Medford, OR Region Firm Customers, 2021-2040 (2018 IRP)
55,000
60,000
65,000
70,000
75,000
80,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
Medford Base-line 2018 Medford Base-line 2021
IRP Avg.Annual Growth
2021-2037
2021 0.9%
2018 0.9%≈ +310
38
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 524 of 794
Roseburg, OR Region Firm Customers, 2021-2040 (2018 IRP)
14,000
15,000
16,000
17,000
18,000
19,000
20,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
Roseburg Base-line 2018 Roseburg Base-line 2021
≈ -1,900
IRP Avg.Annual Growth
2021-2040
2021 0.4%
2018 0.9%
39
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 525 of 794
Klamath, OR Region Firm Customers, 2021-2040 (2018 IRP)
15,000
16,000
17,000
18,000
19,000
20,000
21,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
Klamath Base-line 2018 Klamath Base-line 2021
IRP Avg.Annual Growth
2021-2040
2021 0.7%
2018 1.0%
≈ -1,200
40
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 526 of 794
La Grande, OR Region Firm Customers, 2021-2040 (2018
IRP)
7,400
7,600
7,800
8,000
8,200
8,400
8,600
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
La Grande Base-line 2018 La Grande Base-line 2021
IRP Avg.Annual Growth
2021-2040
2021 0.5%
2018 0.5%
≈ +30
41
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 527 of 794
System Firm Customers, 2021-2040 (2018 IRP)
320,000
340,000
360,000
380,000
400,000
420,000
440,000
460,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
WA-ID-OR Base 2018 WA-ID-OR Base 2021
≈ -1,400
IRP Avg.Annual Growth
2021-2040
2021 1.0%
2018 1.1%
42
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 528 of 794
WA-ID Region Firm Customer Range, 2021-2045
220,000
240,000
260,000
280,000
300,000
320,000
340,000
360,000
380,000
400,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
WAIDFIRMCUS Base WAIDFIRMCUS High WAIDFIRMCUS Low
Variable Low
Growth
Base
Growth
High
Growth
WA-ID Customers 0.7%1.1%1.5%
WA Population 0.4%0.7%1.0%
ID Population 0.8%1.4%2.0%
WA-ID Population 0.5%0.8%1.2%
43
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 529 of 794
OR Region Firm Customer Range, 2021-2045
95,000
100,000
105,000
110,000
115,000
120,000
125,000
130,000
135,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
ORFIRMCUS Base ORFIRMCUS High ORFIRMCUS Low
Variable Low
Growth
Base
Growth
High
Growth
Customers 0.5%0.7%0.9%
Population 0.3%0.5%0.7%
44
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 530 of 794
System Firm Customer Range, 2021-2045
300,000
350,000
400,000
450,000
500,000
550,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
SYSTEMCUS.syf Base SYSTEMCUS.syf High SYSTEMCUS.syf Low
Variable Low
Growth
Base
Growth
High
Growth
Customers 0.6%1.0%1.3%
Population 0.4%0.8%1.1%
45
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 531 of 794
Summary of Growth Rates
System Base-Case High Low
Residential 1.0%1.4%0.7%
Commercial 0.5%0.8%0.1%
Industrial -0.8%2.2%-3.8%
Total 1.0%1.3%0.6%
WA Base-Case High Low
Residential 1.0%1.3%0.7%
Commercial 0.4%0.7%0.1%
Industrial -0.8%1.9%-3.6%
Total 1.0%1.3%0.7%
ID Base-Case High Low
Residential 1.4%2.0%0.8%
Commercial 0.4%1.0%-0.2%
Industrial -1.0%1.8%-3.4%
Total 1.3%1.9%0.7%
OR Base-Case High Low
Residential 0.7%0.9%0.5%
Commercial 0.6%0.8%0.4%
Industrial 0.0%4.5%-10.6%
Total 0.7%0.9%0.5%
46
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 532 of 794
1
Avista –2020 Natural Gas Integrated Resource Plan
Technical Advisory Committee # 3
September 30, 2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 533 of 794
2
2020 Natural Gas IRP Schedule
TAC 3: Wednesday, September 30, 2020: Distribution, Avista’s current supply-side resources overview, supply side
resource options, renewable resources, Carbon cost, price elasticity, sensitivities and portfolio selection modeling.
TAC 2 (Dual Meeting with Power side): Thursday, August 6, 2020: Market Analysis, Price Forecasts, Cost Of
Carbon, Environmental Policies
•Demand Results and Forecasting –August 18, 2020
TAC 1: Wednesday, June 17, 2020: TAC meeting expectations, 2020 IRP process and schedule, energy efficiency
update, actions from 2018 IRP, and a Winter of 2018-2019 review. Procurement Plan and Resource Optimization
benefits. fugitive Emissions, Weather Analysis, Weather Planning Standard
TAC 4: Wednesday, November 18, 2020: CPA results from AEG & ETO, review assumptions and action items, final
modeling results, portfolio risk analysis and 2020 Action Plan.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 534 of 794
3
Agenda
•Introductions/Agenda 30 minutes 9:00 AM –9:30 AM
•Avista and Carbon Reduction 15 minutes 9:30 AM –9:45 AM
•Current Supply Side Resources 30 minutes 9:45 AM –10:15 AM
•BREAK 15 minutes 10:15 AM –10:30 AM
•Renewable Natural Gas 60 minutes 10:30 AM –11:30 AM
•Hydrogen 30 minutes 11:30 AM –12:00 PM
•LUNCH BREAK 60 minutes 12:00 PM –1:00 PM
•Distribution 60 minutes 1:00 PM –2:00 PM
•Supply Side Resource Options 30 minutes 2:00 PM –2:30 PM
•Carbon Costs/Price Elasticity 30 minutes 2:30 PM –3:00 PM
•Sensitivities 30 minutes 3:00 PM –3:30 PM
Topic Length Start Time –End Time
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 535 of 794
4
Avista and Carbon Reduction
Jody Morehouse
Director –Natural Gas Supply
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 536 of 794
5
Planning for a Deeply Decarbonized Future
Active Energy Policy Environment
•Washington
–Carbon reduction goal House Bill 2311
–RNG/EE House Bill 1257
•Oregon:
–RNG Senate Bill-98
–Cap and Reduce Executive Order 20-04
*Focus on solutions that balance carbon reduction, affordability, and reliability*
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 537 of 794
6
Avista's Environmental Objectives
•Build further recognition of Avista’s continued commitment to environmental stewardship
•Acquire renewable supplies based on the demand of our customer base and/or policy
direction
•Fully account for all costs of natural gas including carbon attributed to upstream emissions
•Continue to engage with state and local governments on all existing and future climate
policy
•Increase understanding of how natural gas currently works as part of the energy ecosystem,
ensuring that customers have choices for their energy needs that include access to reliable
energy at affordable prices
•Demonstrate Avista’s leadership in responsibly managing a transition to a cleaner energy
mix while being sensitive to customers’ and other stakeholders’ interests
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 538 of 794
7
Natural Gas is an Important Part of a Clean Energy
Future
•In the right applications, direct use of natural gas is best use
•Natural gas generation provides critical capacity as renewables expand
until utility-scale storage is cost effective and reliable
•Full electrification can lead to unintended consequences:
o Creates new generation needs that may increase carbon footprint
o Drives new investment in electric distribution, generation, and
transmission infrastructure, causing bill pressure
o Home and business conversion costs borne by customers
•Customers have paid for a vast pipeline infrastructure that can utilized for a
cleaner future by transitioning the fuel and keeping the pipe
•A comprehensive view of the energy ecosystem leads to a diversified
approach to energy supply that includes natural gas
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 539 of 794
8
Benefits of Natural Gas
•For Customers. Natural gas is affordable, resilient, and
reliable.
•For Society. Natural gas is an abundant energy resource
produced in North America, which helps lessen our
dependency on foreign oil.
•For Innovation.Natural gas can play a supporting role in
expanding the use of renewable energy sources.
•For Environment.Natural gas is the cleanest burning
fossil fuel, so it helps reduce smog and greenhouse gas
emissions.
•For Economy.Natural gas provides nearly a fourth of
North America's energy today.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 540 of 794
9
Current Supply Side Resources
Justin Dorr
Resource Manager, Natural Gas Supply
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 541 of 794
101010
Interstate Pipeline Resources
•The Integrated Resource Plan (IRP) brings together the various
components necessary to ensure proper resource planning for reliable
service to utility customers.
•One of the key components for natural gas service is interstate pipeline
transportation.Low prices, firm supply and storage resources
are meaningless to a utility customer without the ability to transport the
gas reliably during cold weather events.
•Acquiring firm interstate pipeline transportation provides the most reliable
delivery of supply.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 542 of 794
111111
Pipeline Contracting
Simply stated: The right to move (transport) a specified
amount of gas from Point A to Point B
A B
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 543 of 794
121212
•Firm transport
–Point A to Point B
•Alternate firm
–Point C to Point D
•Seasonal firm
–Point A to Point B but only in winter
•Interruptible
–Maybe it flows, maybe it doesn’t
Contract Types
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 544 of 794
1313
Avista's Transportation Contract Portfolio
Avista holds firm transportation capacity on 6 interstate pipelines:
Pipeline Expirations Base Capacity Dth
Williams NWP 2025 –2042 (2035)290,000
Westcoast
(Enbridge)
2026 10,000
TransCanada -
NGTL
2024-2046 208,000
TransCanada -
Foothills
2024-2046 204,000
TransCanada -
GTN
2023-2028 210,000
164,000
TransCanada-
Tuscarora
2023 200
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 545 of 794
14
Pipeline Overview
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 546 of 794
1515
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 547 of 794
161616
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 548 of 794
1717
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 549 of 794
1818
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 550 of 794
191919
Storage –A valuable asset
•Peaking resource
•Improves reliability
•Enables capture of price spreads between time periods
•Enables efficient counter cyclical utilization of transportation (i.e.
summer injections)
•May require transportation to service territory
•In-service territory storage offers most flexibility
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 551 of 794
2020
Washington and Idaho
Owned Jackson Prairie
•7.7 Bcf of Capacity with approximately 346,000 Dth/d of deliverability
Oregon
Owned Jackson Prairie
•823,000 Dth of Capacity with approximately 52,000 Dth/d of deliverability
Leased Jackson Prairie
•95,565 Dth of Capacity with approximately 2,654 Dth/d of deliverability
Avista's Storage Resources
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 552 of 794
2121
The Facility
•Jackson Prairie is a series of deep,
underground reservoirs –basically
thick, porous sandstone deposits. •The sand layers lie approximately
1,000 to 3,000 feet below the
ground surface. •Large compressors and pipelines are
employed to both inject and
withdraw natural gas at 54 wells
spread across the 3,200 acre facility.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 553 of 794
2222
Renewable Natural Gas (RNG)
Michael Whitby, RNG Manager
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 554 of 794
232323
Advancing RNG at Avista
Avista has been actively preparing to participate in RNG. The following topics
covered in this section of the presentation are as follows:
▪Renewable Natural Gas (RNG) Explained
▪RNG –A Climate Change Solution
▪Policy & Regulation
▪Industry Reports
▪Avista’s Commitment to Carbon Reduction
▪Avista’s RNG Program & Team
▪Program Considerations
▪RNG Market Studies & Voluntary Customer Program
▪Pipeline Safety & Interconnection Requirements
▪Environmental Attribute Tracking & Banking
▪RNG Production Technologies & Project Types
▪RNG Opportunities and Challenges
▪Cost Effectiveness Evaluation Methodology
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 555 of 794
242424
Renewable Natural Gas (RNG) Explained
Natural Gas is Critical to a Clean Energy Future
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 556 of 794
2525
RNG –A Climate Change Solution
Natural gas plays critical role for meeting aggressive green house gas (GHG) reductions goals, RNG even more so!
▪Advantages of RNG
▪“De-carbonizes” gas stream
▪Gives customers another renewable choice
▪RNG is a strong pathway option for decarbonizing the thermal market
▪RNG utilizes existing infrastructure as it is fully interchangeable with conventional natural gas with no end user equipment modifications or replacement
▪RNG is a more economical solution than electrification which requires the procurement of added renewable electric resources, distribution system
upgrades, and has a significant impact to end users due to the necessary replacement of building equipment and systems
▪In the right applications, direct use of natural gas is best use
▪Natural gas generation provides critical capacity as renewables expand until
utility-scale storage is cost effective and reliable
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 557 of 794
262626
Washington HB 2580
▪RNG study requested by legislature from WA Department of Commerce & WSU Energy
Program
Washington HB 1257
▪Building efficiency bill that includes RNG
▪Requires utilities to offer voluntary RNG programs/products to customers
▪Allows utilities to invest in RNG projects and recover the costs
Oregon SB 334
▪Directs the Oregon Department of Energy to conduct a biogas and renewable natural gas
inventory and prepare a report
Oregon SB 98 & AR 632 Rule Making
▪Final rules effective on July 17th 2020
▪Allows investment recovery, percent of revenue requirement per year to be determined
based on potential project costs & timing, pending petition to participate
▪Allows investment in gas conditioning equipment without RFP process
Policy & Regulation:
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 558 of 794
272727
Avista is familiar with these relevant industry reports and has utilized them to
understand the RNG industry in general as well as the potential in Washington
& Oregon
Industry Reports:
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 559 of 794
282828
RNG is a Pathway to Decarbonizing the Natural Gas System
▪By utilizing waste streams to create green fuel, RNG can play an important
role in supporting Avista’s environmental strategy
▪RNG provides Avista’s customers with a new environmentally friendly, low
carbon fuel choice, delivered seamlessly via Avista’s existing natural gas
system
Avista’s Commitment to Carbon Reduction
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 560 of 794
292929
Avista’s RNG Program & Team
Avista has been assessing and planning for RNG
▪Program Manager in place
▪Program Charter in place
▪Program Execution Plan drafted
▪Participation in the regulatory and rule making process in OR & WA, informal and formal
▪Business Development efforts in pursuit of multiple RNG projects continues
▪Business Cases developed for consideration in Avista’s five year capital planning cycle
▪RNG Project accounting established
▪Cross-functional team in place to support RNG:
▪Gas Engineering
▪Gas Supply
▪Legal
▪Governmental Affairs
▪Regulatory Affairs
▪Products & Services
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 561 of 794
303030
Program Considerations
▪Evaluate available RNG procurement options
▪Pursue potential RNG development opportunities from local RNG feedstock
resources under new legislation (Washington HB 1257 & Oregon SB 98)
▪Develop an understanding of RNG development cost, cost recovery impacts to customers,
resulting supply volumes and RNG costs
▪Evaluate potential RNG customer market demands vs. supply
▪Participation in rule making and policy:
▪Participation in HB 1257 Policy development
▪Participation in SB 98 Policy Rulemaking via AR 632 informal and formal
▪Cost recovery proposal led by NWGA with input from all four Washington LDC’s
▪Collaborative RNG Gas Quality Framework established across four WA LDC’s
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 562 of 794
313131
RNG Market Studies & Voluntary Customer
Program
▪RNG Commercial Market Study completed in 2019
▪RNG Residential Market Survey concluded in September 2020
▪Customers lack understanding of RNG since it is a new concept
▪Customers like the environmental aspects of RNG
▪Customers like to choose their level of participation to manage costs predictably
▪Voluntary customer RNG program design will advance based on the studies above
▪Estimate voluntary customer program demands
▪RNG to be added to Avista’s renewables portfolio
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 563 of 794
323232
Pipeline Safety & Interconnection Requirements
▪Avista Gas Quality Specification developed
▪Collaborative RNG Gas Quality Framework established across (4) WA LDC’s
▪Avista Interconnection Agreement template developed
▪Avista Study Agreement and RNG Producer review process template developed
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 564 of 794
333333
Environmental Attribute Tracking & Banking
Under OR SB 98 the M-RETS system has been selected to track RNG
environmental attributes. Other jurisdictions including Washington may also
select this system
▪1 Renewable Thermal Certificate (RTC) = 1 Dekatherm (Dth) of RNG
▪Transparent electronic certificate tracking
▪Not a certification entity
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 565 of 794
343434
RNG Production Technologies & Project Types
Avista is actively evaluating a handful of potential Anaerobic Digestion
Projects throughout Washington and Oregon.
RNG Technologies :
▪Conventional RNG: Amine scrub, membrane separation, water wash, PSA
▪Hydrogen blending
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 566 of 794
353535
RNG Opportunities & Challenges
California RNG market ($30+/Dth v. $2/Dth)
▪Vehicle emission incentives shut-out other potential end users
▪Producers see the pot of gold in Federal RIN & California LCFS markets
▪RNG supplier cost volatility
Financing for producers
▪RIN market is volatile
▪No forward pricing for RNG RTC’s in carbon market
▪Vehicle market may be approaching saturation in CA
▪Environmental attribute value for local markets is undefined
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 567 of 794
363636
RNG Opportunities & Challenges
Utility RNG Projects
▪Feedstock owners can now partner with LDC’s to cultivate new RNG projects
▪Feedstock owners wiliness to partner with the utility’s cost of service model. This is a foreign
concept to feedstock owners that seek highest value for their biogas
▪LDC’s are credit worthy partners offering long term off-take contracts to feedstock owners
▪Each RNG project is unique with respect to capital development costs & resulting RNG costs
▪Each RNG project will vary in size, location and distance to interconnection pipeline,
feedstock type, gas conditioning equipment and requirements and operating costs
▪Economies of scale –Low volume biogas opportunities face economic challenges
▪New RNG Projects can take 2-3 years to develop
▪Customers have paid for a vast pipeline infrastructure that can be utilized for a cleaner future
by transitioning the fuel and keeping the pipe
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 568 of 794
373737
RNG Opportunities & Challenges
Source: Promoting RNG in WA State
Avista Owned and Operated
ID -WA
2035 Premium
Estimate ($ / Dth)
RNG -Landfills $7 -$10
RNG -Waste Water Treatment Plants (WWTP)$12 -$22
RNG -Agriculture Manure $28 -$53
RNG -Food Waste $29 -$53
RNG $ per Dth/MMBtu
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 569 of 794
383838
Carbon Intensity will pay a role in how the environmental attributes /
Renewable Thermal Certificate (RTC) values will be determined
RNG Opportunities & Challenges
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 570 of 794
393939
RNG RTC values within the utility construct cannot compete with the RNG values driven
by the RFS RIN & LCFS markets
RIN = renewable identification number
Source: CARB
Source: EPA
RNG Opportunities & Challenges
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 571 of 794
4040
WA RNG Report (HB 2580) –Utility’s have the opportunity to leverage the
remaining RNG opportunities to decarbonize the natural gas system
*Released December 1, 2018
WSU Energy Program, Harnessing Renewable Natural Gas for Low-Carbon Fuel: A Roadmap for Washington State
0
500,000
1,000,000
1,500,000
2,000,000
2,500,000
Cedar Hills
Landfill (King
County)
Roosevelt
Landfill
(Republic
Services)
Klickitat
County PUD
South
Treatment
Plant (King
County) Puget
Sound Energy
Landfills Wastewater
treatment
plants
Dairy
digesters
Municipal
food waste
digesters
Food
processing
residuals
Food
processed at
compost
facilities
Landfills Wastewater
treatment
plants
Dairy
digesters
Municipal
food waste
digesters
Dth
Existing Projects
Near Term Projects
Medium Term Projects
RNG Opportunities & Challenges
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 572 of 794
414141
Cost Effectiveness Evaluation Methodology
Developing the Methodology….a work in process
▪Avista is creating a cost effectiveness evaluation methodology for evaluating RNG
projects. The following slides are a snapshot of Avista’s work in progress.
▪The methodology shown is derived from OPUC UM2030, also referenced in the OPUC SB 98 AR 632 Rulemaking
▪The evaluation method shown herein is subject to input, refinement and reconsideration.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 573 of 794
42
Hydrogen
Tom Pardee
Planning Manager, Natural Gas Supply
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 574 of 794
43
Hydrogen
•The energy factor of H2 Low Heating Value (LHV) is roughly equivalent to a
gallon of gasoline or 114,000btu
–This equates to 8.78 kg of H2LHV per Dth
•Most H2 is currently made from reforming natural gas
–The energy can come from Nuclear (Pink), Renewables (Green) or Fossil fuels (Grey)
•High cost (currently) when compared to energy in a Dth combined with
current prices of natural gas
•Hydrogen can only be stored in the pipeline as a % of gas or combined with a
carbon source to produce methane.
•Hydrogen is lighter than air and diffuses rapidly (3.8x faster than natural gas)
making it more difficult to contain
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 575 of 794
44
PtG Process
Source: http://www.europeanpowertogas.com/about/power-to-gas
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 576 of 794
45
Power to Gas
•Power to Gas (PtG) is a process using power to separate water into
hydrogen and oxygen
•Hydrogen can be stored, as a % of gas, in the existing gas grid or used in the
mobility sector (blend up to 20%)
•PtG can help to balance excess power from intermittent sources like wind
and solar
•PtG can decarbonize the direct use of natural gas
•PtG economics will advance as more renewables are added and the
technology matures
•Short term and seasonal energy storage
•Stored in the existing gas pipeline
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 577 of 794
46
PtG Benefits
Benefits
•Cleans up the grid using excess power
•Stores the energy for future use in the natural gas pipelines/infrastructure
utilizing customer owned resources and are currently available
•Hydrogen is relatively safe as if it is released it quickly dilutes into a non -
flammable concentration
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 578 of 794
47
Current Renewable Hydrogen Price estimates
$0.00
$10.00
$20.00
$30.00
$40.00
$50.00
$60.00
$70.00
$
p
e
r

M
M
B
t
u
Average –System Hydrogen costs
*Assumes Avista owned resources
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 579 of 794
48
Distribution Overview
Terrence Browne
Sr. Gas Planning Engineer, Gas Engineering
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 580 of 794
49
Mission
•Using technology to plan and design a safe, reliable, and economical distribution
system
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 581 of 794
50
Gas Distribution Planning
•Service Territory and Customers
•Scope of Gas Distribution Planning
•SynerGi Load Study Tool
•Planning Criteria
•Interpreting Results
•Long-term Planning Objectives
•Monitoring Our System
•Communicating Solutions
•Gate Station Capacity Review
•Project Examples
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 582 of 794
51
–Population of service area 1.5 million
385,000 electric customers
360,000 natural gas customers
Service Territory and Customer Overview
•Serves electric and natural gas customers in eastern Washington and northern Idaho,
and natural gas customers in southern and eastern Oregon
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 583 of 794
52
Seasonal Demand Profiles
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 584 of 794
53
Our Planning Models
•120 cities
•40 load study models
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 585 of 794
54
__
Pup Pdown
Q
L ||
D
__
5 Variables for Any Given Pipe
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 586 of 794
55
Scope of Gas Distribution Planning
Supplier Pipeline
High Pressure Main
Reg.
Distribution Main and Services
Reg.Reg.
Gate
Sta.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 587 of 794
56
Scope of Gas Distrib. Planning cont.
Gate
Sta.
Reg.Reg.Reg.
Reg.Reg.
Gate
Sta.
Gate
Sta.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 588 of 794
57
SynerGi (SynerGEE, Stoner) Load Study
•Simulate distribution behavior
•Identify low pressure areas
•Coordinate reinforcements with expansions
•Measure reliability
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 589 of 794
58
35 DD
30’ F
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 590 of 794
59
Preparing a Load Study
•Estimating Customer Usage
•Creating a Pipeline Network
•Join Customer Loads to Pipes
•Convert to Load Study
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 591 of 794
60
Estimating Customer Usage
•Gathering Data
–Days of service
–Degree Days
–Usage
–Name, Address, Revenue Class, Rate Schedule…
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 592 of 794
61
Estimating Customer Usage cont.
•Degree Days
–Heating (HDD)
–Cooling (CDD)
•Temperature -Usage Relationship
–Load vs. HDD’s
–Base Load (constant)
–Heat Load (variable)
–High correlation with residential
Avg. Daily Heating Cooling
Temperature Degree Days Degree Days
('Fahrenheit) (HDD) (CDD)
85 20
80 15
75 10
70 5
65 0 0
60 5
55 10
50 15
45 20
40 25
35 30
30 35
25 40
20 45
15 50
10 55
5 60
4 61
0 65
-5 70
-10 75
-15 80
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 593 of 794
62
Heat Base
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 594 of 794
63
Creating a Pipeline Model
•Elements
–Pipes, regulators, valves
–Attributes: Length, internal diameter,
roughness
•Nodes
–Sources, usage points, pipe ends
–Attributes: Flow, pressure
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 595 of 794
64
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 596 of 794
65
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 597 of 794
66
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 598 of 794
67
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 599 of 794
68
Balancing Model
•Simulate system for any temperature
–HDD’s
•Solve for pressure at all nodes
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 600 of 794
69
35 DD
30˚F
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 601 of 794
70
Validating Model
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 602 of 794
71
Validating Model cont.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 603 of 794
72
•Simulate recorded condition
•Electronic Pressure Recorders
–Do calculated results match field data?
•Gate Station Telemetry
–Do calculated results match source data?
•Possible Errors
–Missing pipe
–Source pressure changed
–Industrial loads
Validating Model cont.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 604 of 794
73
•Reliability during design HDD
–Spokane 77 HDD (avg. daily temp. -12’ F)
–Medford 54 HDD (avg. daily temp. 11’ F)
–Klamath Falls 74 HDD (avg. daily temp. -9’ F)
–La Grande 76 HDD (avg. daily temp. -11’ F)
–Roseburg 51 HDD (avg. daily temp. 14’ F)
•Maintain minimum of 15 psig in system at all times
–5 psig in lower MAOP areas
Planning Criteria
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 605 of 794
74
35 DD
30˚F
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 606 of 794
75
50 DD
15˚F
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 607 of 794
76
65 DD
0˚F
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 608 of 794
77
Interpreting Results
•Identify Low Pressure Areas
–Number of feeds
–Proximity to source
•Looking for Most Economical Solution
–Length (minimize)
–Construction obstacles (minimize)
–Customer growth (maximize)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 609 of 794
78
65 DD
0’ F
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 610 of 794
79
65 DD
0’ F
R
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 611 of 794
80
80 DD
-15’ F
R
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 612 of 794
81
Long-term Planning Objectives
•Future Growth/Expansion
•Design Day Conditions
•Facilitate Customer Installation Targets
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 613 of 794
82
Monitoring Our System
•Electronic Pressure Recorders
•Daily Feedback
•Real time if necessary
•Validates our Load Studies
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 614 of 794
83
Real-time Pressure & Flow Monitoring
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 615 of 794
84
ERX #007
West Medford 6 psig
System
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 616 of 794
85
ERX #007: West Medford 6 psig System, OR
12/18/2016
12/26/2016
01/06/2017
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 617 of 794
86
2019-2020 Winter
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 618 of 794
87
2013-2014 Winter
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 619 of 794
88
1)Notify service area manager
2)Show where and at what temperature we think we’ll have low
pressure
3)Identify possible solutions like:
•Curtailing interruptible customers
•Ask schools & businesses to voluntarily lower thermostats
•Bring out CNG trailers
4)Continue to monitor forecast to see if temperatures improve
or get worse
5)Share plan with Gas Controllers
6)Pray for warmer weather…
What I do when “things” look bad?
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 620 of 794
89
Communicating Solutions
Add
4”
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 621 of 794
90
Gas Planning AOI
Low
pressure
Future
Growth
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 622 of 794
91
Solutions: long-term reinforcements
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 623 of 794
92
Gate Station Capacity Review
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 624 of 794
93
y = 0.1278x + 3.5481
R² = 0.64840
5
10
15
20
25
30
35
0 10 20 30 40 50 60 70 80 90 100
Fl
o
w

(
m
c
f
h
)
HDDCity Gate Station # X
Daily Peak Flow (mcfh)
GTN Physical Capacity
(31 mcfh)
Design Day Peak Flow
(14.0 mcfh; 82 HDD)
Contractual Amount
(21.9 mcfh, Diversity
Factor = 1.5)
Linear (Daily Peak Flow
(mcfh))
77 HDD
Gate Station Capacity Review (example)
77
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 625 of 794
94
y = 2.1146x + 65.605
R² = 0.63080
50
100
150
200
250
300
0 10 20 30 40 50 60 70 80 90 100
Fl
o
w

(
m
c
f
h
)
HDD
City Gate Station # Y
Daily Peak Flow (mcfh)
NWP Physical Capacity
(206.0 mcfh, Diversity
Factor = 1.44)
Design Day Peak Flow
(239.0 mcfh; 82 HDD)
Contractual Amount
(121.8 mcfh, Diversity
Factor = 1.44)
Linear (Daily Peak Flow
(mcfh))
77
77 HDD
Gate Station Capacity Review (example)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 626 of 794
95
Recent Projects and
Examples
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 627 of 794
96
New Agri-Industrial Customer
Service Request
Roseburg, OR
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 628 of 794
97
0.01 –15.00
Facilities Color By:
Pressure (psig)
15.01 –30.00
30.01 –45.00
45.01 –60.00
> 60.01
0.00
Agri-Industrial Customer Service Request
Conditions:
•21 Mcfh
•15 psig
•year-round
•51 HDD
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 629 of 794
98
Agri-Industrial Customer Service Request
0.01 –15.00
Facilities Color By:
Pressure (psig)
15.01 –30.00
30.01 –45.00
45.01 –60.00
> 60.01
0.00
Conditions:
•21 Mcfh
•15 psig
•year-round
•51 HDD
47 HDD
18 Mcfh
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 630 of 794
99
Residential Development
Service Request
Deer Park, WA
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 631 of 794
100
Residential Development Study
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 632 of 794
101
Residential Development Study
0.01 –15.00
Facilities Color By:
Pressure (psig)
15.01 –30.00
30.01 –45.00
45.01 –60.00
> 60.01
0.00
Inadequate Pressure
(less than 15 psig)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 633 of 794
102
Residential Development Study
0.01 –15.00
Facilities Color By:
Pressure (psig)
15.01 –30.00
30.01 –45.00
45.01 –60.00
> 60.01
0.00Recommend:
250-300 2” PE
Acceptable Pressure
(>15 psig)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 634 of 794
103
Medford, OR
Enbridge Pipeline Rupture
Effect on distribution
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 635 of 794
104
Enbridge Pipeline Rupture effect
Roseburg
Grants
Pass Klamath
Falls
Medford
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 636 of 794
105
Grants Pass
Ashland
Medford
450
280 White City Eagle Point
Shady Cove
Enbridge Pipeline Rupture effect
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 637 of 794
106
Grants Pass
Ashland
Medford
450
0
Firm & Transport loads (100%) >> 45 HDD
Firm loads only (79%) >> 51 HDD
White City Eagle Point
Shady Cove
Enbridge Pipeline Rupture effect
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 638 of 794
107
Questions and Discussion
Mission
Using technology to plan and design a safe,
reliable, and economical distribution system
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 639 of 794
108
Unserved Demand and Supply Side Resource Options
Tom Pardee
Planning Manager, Natural Gas Supply
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 640 of 794
109
When unserved demand does show up……
There are a few questions we need to ask:
1.Why is the demand unserved?
2.What is the magnitude of the short? (i.e Are we 1 Dth or 1000 Dth’s short?)
3.What are my options to meet it?
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 641 of 794
110
When current resources don’t meet demand what
could we consider?
•Transport capacity release recalls
•“Firm” backhauls
•Contract for existing available transportation
•Expansions of current pipelines
•Peaking arrangements with other utilities (swaps/mutual assistance agreements) or marketers
•In-service territory storage
•Satellite/Micro LNG (storage inside service territory)
•Large scale LNG with corresponding pipeline build into our service territory
•Structured products/exchange agreements delivered to city gates
•Biogas (assume it’s inside Avista’s distribution)
•Hydrogen blend (assume it’s inside Avista’s distribution)
•Avista distribution system enhancements
•Demand side management
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 642 of 794
111
New Resource Risk Considerations
•Does is get supply to the gate?
•Is it reliable/firm?
•Does it have a long lead time?
•How much does it cost?
•New build vs. depreciated cost
•The rate pancake
•Is it a base load resource or peaking?
•How many dekatherms do I need?
•What is the “shape” of resource?
•Is it tried and true technology, new technology, or yet to be discovered?
•Who else will be competing for the resource?
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 643 of 794
112
Potential New Supply Resources Considerations
•Availability
–By Region –which region(s) can the resource be utilized?
–Lead time considerations –when will it be available?
•Type of Resource
–Peak vs. Base load
–Firm or Non-Firm
–“Lumpiness”
•Usefulness
–Does it get the gas where we need it to be?
–Last mile issues
•Cost
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 644 of 794
113
Regional Infrastructure –Potential Projects
NWGA –2020 Outlook
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 645 of 794
114
Supply Resources -Modeled
Additional Resource Size Availability Notes
Unsubscribed GTN Capacity Up to 50,000 Dth Now Currently available unsubscribed capacity from Kingsgate to
Spokane
Medford Lateral Exp 50,000 Dth / Day 2022 Additional compression to facilitate more gas to flow from
mainline GTN to Medford
WA ID OR
$48 / Dth $40 / Dth $46 / Dth
WA ID OR
$13 / Dth $13 / Dth $13 / Dth
WA ID OR
$11 / Dth $11 / Dth $12 / Dth
WA ID OR
$34 / Dth $39 / Dth $33 / Dth
WA ID OR
$19 / Dth $18 / Dth $19 / Dth
WA ID OR
$38 / Dth $39 / Dth $38 / Dth
Plymouth LNG
241,700 Dth
w/70,500 Dth
deliverability
Now
Provides for peaking services and alleviates the need for costly
pipeline expansions
Pair with excess pipeline MDDO’s to create firm transport
Hydrogen 166 Dth / Day Varies
Cost estimates obtained from a consultant; levelized cost
includes revenue requirements, expected carbon adder and
assumed retail power rate
Renewable Natural Gas –
Distributed Landfill 635 Dth / Day
NWP Rate
Varies
Costs estimates obtained from a consultant for each specific
type of RNG; levelized costs include revenue requirements,
distribution costs, and projected carbon intensity adder/(savings).
This cost also includes any incentives from bills such as
Washington House Bill 2580 or Oregon Senate Bill 334
VariesRenewable Natural Gas – Dairy 635 Dth / Day
Renewable Natural Gas – Waste
Water 513 Dth / Day Varies
Varies298 Dth / DayRenewable Natural Gas – Food
Waste to (RNG)
Renewable Natural Gas –
Centralized Landfill 1,814 Dth / Day
Cost/Rates
GTN Rate
$35M capital + GTN Rate
Varies
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 646 of 794
115
Future Supply Resources –Not Modeled
Other Resources to Consider
Additional Resource Size Cost/Rates Availability Notes
Co. Owned LNG 600,000 Dth
w/ 150,000 of
deliverability
$75 Million plus
$2 Million annual
O&M
2024 On site, in service territory liquefaction
and vaporization facility
Various pipelines –Pacific
Connector, Trails West, NWP
Expansion, GTN Expansion,
etc.
Varies Precedent
Agreement Rates
2022 Requires additional mainline capacity
on NWPL or GTN to get to service
territory
Large Scale LNG Varies Commodity less
Fuel
2024 Speculative, needs pipeline transport
In Ground Storage Varies Varies Varies Requires additional mainline transport
to get to service territory
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 647 of 794
116
Carbon Costs
Tom Pardee
Planning Manager, Natural Gas Supply
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 648 of 794
117
Cost of Carbon and Sendout
•Monthly costs are loaded into SENDOUT
•These costs will differ based on the requirements or an expected
program type by state
•These costs are input at the transportation level in order to
correctly account for the cost of carbon in each area regardless of
supply basin
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 649 of 794
118
Social Cost of Carbon
•Social cost of carbon dioxide in 2007 dollars using the 2.5% discount rate, listed in table 2, technical support document:
Technical update of the social cost of carbon for regulatory impact analysis under Executive Order No. 12866, published by
the interagency working group on social cost of greenhouse gases of the United States government, August 2016.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 650 of 794
119
Washington –Carbon adder
•Social cost of carbon dioxide in 2007 dollars using the 2.5% discount rate, listed in table 2, technical support document:
Technical update of the social cost of carbon for regulatory impact analysis under Executive Order No. 12866, published by
the interagency working group on social cost of greenhouse gases of the United States government, August 2016.
•Adjust to 2019$ using Bureau of Economics GDP
•Adjust to Nominal $ using 2.11% annual inflation rate
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 651 of 794
120
Oregon –Carbon adder
$0
$20
$40
$60
$80
$100
$120
$140
$160
2019$nominal
Levelized Cost: $44.91 per Metric Ton
Source: Wood Mackenzie North America gas markets long-term outlook –H1 2020
*Modeled as an expected cost of California’s cap and trade program
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 652 of 794
121
All jurisdictions -Carbon adder
High sensitivity
$0.00
$50.00
$100.00
$150.00
$200.00
$250.00
$300.00
$350.00
$400.00
$450.00
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
2007 $SCC (2019$)Nominal $
High Carbon Scenario -SCC @ 95% @ 3%
Levelized Cost: $234.45 per Metric Ton
•EPA –Social Cost of Carbon
•Adjust to 2019$ using Bureau of Economics GDP
•Adjust to Nominal $ using 2.11% annual inflation rate
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 653 of 794
122
Carbon Costs
$-
$50
$100
$150
$200
$250
$300
$350
$400
$450
OR Cap and Trade WA SCC High Carbon Price Low Carbon Price
$44.92 $113.75 $234.45 $0Levelized Cost
per MTCO2e
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 654 of 794
123
Expected Case
Cost of Carbon by State -Summary
•W ashington -Social cost of carbon @ 2.5% discount rate;
–upstream emissions associated with natural gas drilling and transportation of natural gas to its
end use.
•Oregon is based off a Wood Mackenzie estimate for Cap and
Trade
•Idaho -carbon prices will not be included
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 655 of 794
124
Price Elasticity
Tom Pardee
Planning Manager, Natural Gas Supply
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 656 of 794
125
Price Elasticity
Quantity
Price
Demand
$7
$6
150 300
Price Elasticity of Demand = % Change in Quantity
Demanded / % Change in Price
Price elasticity is a method used by economists to measure how supply or
demand changes based on changes in price.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 657 of 794
126
Price Elasticity Factors Defined
•Price elasticity is usually expressed as a numerical factor that defines the
relationship of a consumer’s consumption change in response to price
change.
•Typically, the factor is a negative number as consumers normally reduce
their consumption in response to higher prices or will increase their
consumption in response to lower prices.
•For example, a price elasticity factor of -0.081 means:
•A 10% price increase will prompt a 0.81% consumption decrease
•A 10% price decrease will prompt a 0.81%
•consumption increase
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 658 of 794
127
Summary
•The elasticity as measured in the Medford and Roseburg areas
will be used for the entire system as estimated elasticity.
•0.81% decrease only for each price rise of 10%
•This elasticity is measured through heat coefficients and annual
price changes
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 659 of 794
128
Sensitivities
Michael Brutocao
Analyst, Natural Gas Supply
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 660 of 794
129
Sensitivities Summary
Influence Type Sensitivity Customer Growth Rate Use per Customer Weather Demand Side Management Prices Elasticity
First Year
System Unserved Location Unserved
DEMAND INFLUENCING -DIRECT
Reference Reference
3 Year Historical
20 Year Average
None
Expected None
--
Reference Plus Peak
Planning Standard
2035 Washington
Low Cust Low Growth --
High Cust High Growth 2029 Washington
Alternate Weather Standard
Reference
Coldest in 20yrs 2035 Washington
DSM 20 Year Average Expected --
Peak plus DSM
Planning Standard
2039 Idaho
80% below 1990 emissions –OR/WA only
None
--
2 Year use per customer Alternate 2 Year
Historical 2035 Washington
5 Year use per customer Alternate 5 Year Historical 2035 Washington
JP Outage Only (0% capacity)
3 Year Historical
2021 Washington
AECO Outage Only (0% capacity)2020 WA, ID
Sumas Outage Only (0% capacity)2020 Medford
Rockies Outage Only (0% capacity)2020 La Grande
JP Outage Only (50% capacity)2021 Washington
AECO Outage Only (50% capacity)2026 Washington
Sumas Outage Only (50% capacity)2025 Washington
Rockies Outage Only (50% capacity)2025 La Grande
NWP Outage (0% capacity)2020 WA, ID, La Grande
GTN Outage (0% capacity)2020 WA, ID, Klamath Falls
NWP Outage (50% capacity)2020 WA, La Grande
GTN Outage (50% capacity)2026 Washington
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 661 of 794
130
Sensitivities Summary (Continued)
Influence Type Sensitivity Customer Growth Rate Use per Customer Weather
Demand Side
Management
Prices Elasticity
First Year System
Unserved
Location Unserved
PRICE INFLUENCING -
INDIRECT
Expected Prices
Reference 3 Year
Historical
Planning
Standard None
Expected
Expected
--
Low Prices Low --
High Prices High --
Carbon Cost -High (SCC 95% at 3%)
Expected
--
Carbon Cost -Expected (SCC 2.5% (WA) & Cap&Red (OR))--
Carbon Cost -Low $0 --
EMISSIONS INFLUENCING
High Upstream Emissions 2.47% leakage (EDF study)--
Expected Upstream Emissions (0.79% leakage)--
No Upstream Emissions --
Expected Global Warming Potential (20 Years)--
Expected Global Warming Potential (100 Years)--
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 662 of 794
131
First Year Peak Demand Unserved (11/1/2020 –10/31/2040)
*Sensitivities not listed above have no unserved demand.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 663 of 794
132
Demand Sensitivities: Weather
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 664 of 794
133
Demand Sensitivities: 80% Below 1990 Emissions
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 665 of 794
134
Demand Sensitivities: Demand Side Management
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 666 of 794
135
Demand Sensitivities: Use Per Customer
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 667 of 794
136
Demand Sensitivities: Customer Growth
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 668 of 794
137
Demand Sensitivities: Price and Carbon Elasticities
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 669 of 794
138
Demand Sensitivities: Price (with Elasticities)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 670 of 794
139
Demand Sensitivities: Carbon (with Elasticities)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 671 of 794
140
Demand Sensitivities: Upstream Emissions (with
Elasticities)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 672 of 794
141
Demand Sensitivities: GWP (with Elasticities)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 673 of 794
142
Demand (11/1/2020 –10/31/2040)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 674 of 794
143
Demand and
Supply Side
Sensitivities
Optimize
Resource
Portfolios
Stochastic
Cost/Risk Analysis
By Resource
Highest
Performing
Portfolios
selection
Preferred
Resource
Strategy
Core Cases Price Forecast
Sensitivities, Scenarios, Portfolios
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 675 of 794
144
Proposed Scenarios
*1,000 Draws per scenario will be run stochastically
Proposed Scenarios Expected Average Low Growth High Growth
INPUT ASSUMPTIONS Case Case & High Prices & Low Prices
Customer Growth Rate Low Growth Rate Reference Case Cust Growth Rates High Growth Rate
Demand Side Management High Prices DSM
Weather Planning Standard
99% probability of coldest
in 30 years 20 year average
GWP
Prices
Price curve
SCC @ 2.5% WA; Cap and Trade
forecast - OR;
NO Carbon adder in IDRESULTS
First Gas Year Unserved
Washington
Idaho
MedfordRoseburg
Klamath
La Grande
Scenario Summary
Most aggressive peak
planning case utilizing Average Case
assumptions as a starting
point and layering in peak
day 99% probability. The likelihood of occurrence is
low.
Case most
representative of our average (budget,
PGA, rate case)
planning criteria.
Stagnant growth
assumptions in order to evaluate if a
shortage does occur.
Not likely to occur.
Reduction of the use of natural gas to 80%
below 1990 targets in OR and WA by 2050. The case assumes the overall
reduction is an average goal before
applying figures like elasticity and DSM.
Aggressive growth
assumptions in order to evaluate when our
earliest resource
shortage could occur.
Not likely to occur.
Carbon Reduction
Carbon Cost - High
(SCC 95% at 3%)
SCC @ 2.5% WA; Cap and Trade forecast - OR;
Reference Case Cust Growth Rates
LowExpectedHigh
Carbon Legislation
($/Metric Ton)
Use per Customer
100-Year GWP
NO Carbon adder in ID
3 yr + Price Elasticity
99% probability of coldest in 30 years
$0
Expected Case CPA Low Prices DSM
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 676 of 794
145
2020 Natural Gas IRP Schedule
TAC 3: Wednesday, September 30, 2020: Distribution, Avista’s current supply-side resources overview, supply side
resource options, renewable resources, Carbon cost, price elasticity, sensitivities and portfolio selection modeling.
TAC 2 (Dual Meeting with Power side): Thursday, August 6, 2020: Market Analysis, Price Forecasts, Cost Of
Carbon, Environmental Policies
•Demand Results and Forecasting –August 18, 2020
TAC 1: Wednesday, June 17, 2020: TAC meeting expectations, 2020 IRP process and schedule, energy efficiency
update, actions from 2018 IRP, and a Winter of 2018-2019 review. Procurement Plan and Resource Optimization
benefits. fugitive Emissions, Weather Analysis, Weather Planning Standard
TAC 4: Wednesday, November 18, 2020: CPA results from AEG & ETO, review assumptions and action items, final
modeling results, portfolio risk analysis and 2020 Action Plan.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 677 of 794
11
Natural Gas Integrated Resource Plan
TAC #4
November 18, 2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 678 of 794
2222
Agenda
1.CPA results from AEG (60 minutes) –Ken Walter
2.CPA results from ETO (60 minutes) –Spencer Moersfelder, Ted Light
3.Break (15 minutes)
4.Sendout Model (15 minutes) –Tom Pardee
5.Review assumptions (30 minutes) –Tom Pardee
6.Lunch break (60 minutes)
7.Final modeling results for Expected Case (60 minutes) –Tom Pardee
8.Final modeling results for Other Scenarios (60 minutes) –Tom Pardee
9.Action Plan and Next Steps (30 minutes) –Tom Pardee
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 679 of 794
3333
2020 Natural Gas IRP Schedule
TAC 3: Wednesday, September 30, 2020: Distribution, Avista’s current supply-side
resources overview, supply side resource options, renewable resources, Carbon cost,
price elasticity, sensitivities and portfolio selection modeling.
TAC 2 (Dual Meeting with Power side): Thursday, August 6, 2020: Market Analysis, Price
Forecasts, Cost Of Carbon, Environmental Policies
•Demand Results and Forecasting –August 18, 2020
TAC 1: Wednesday, June 17, 2020: TAC meeting expectations, 2020 IRP process and
schedule, energy efficiency update, actions from 2018 IRP, and a Winter of 2018-2019
review. Procurement Plan and Resource Optimization benefits. fugitive Emissions,
Weather Analysis, Weather Planning Standard
TAC 4: Wednesday, November 18, 2020: CPA results from AEG & ETO, review
assumptions and action items, final modeling results, portfolio risk analysis and 2020
Action Plan.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 680 of 794
Energy solutions. Delivered.
2020 CONSERVATION POTENTIAL
ASSESSMENT –UPDATE
Prepared for the Avista Technical Advisory Committee
November 18, 2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 681 of 794
| 5Applied Energy Group · www.appliedenergygroup.com
AVISTA 2020 NATURAL GAS CPA
CPA Methodology Overview
•Review of AEG Approach
•Levels of Potential
•Economic Screening and IRP Integration
•Retained enhancements from 2018 Action Plan
Summary of Results
•Summary of Potential
▪High level potential
▪Technical Achievable compared to Economic potential
•Comparison to previous CPA
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 682 of 794
| 6Applied Energy Group · www.appliedenergygroup.com
ABOUT AEG
Planning
Baseline studies
Market
assessment studies
Program design &
action plans
End-use forecasting
EM&V
EE portfolio & targeted
programs
Demand response programs
& dynamic pricing
Pilot design & experimental
design
Behavioral programs
Implementation &
Technical Services
Engineering review, due-
diligence, QA/QC
M&V, modeling &
simulation, onsite
assessments
Technology R&D and data
tools (DEEM)
Program admin,
marketing,
implementation,
application processing
Market Research
Program / service pricing
optimization
Process evaluations
Market assessment /
saturation surveys
Customer satisfaction /
customer engagement
Market segmentation
VISION DSMTM Platform
Full DSM lifecycle tracking & reporting
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 683 of 794
| 7Applied Energy Group · www.appliedenergygroup.com
Including Potential Studies and End-Use Forecasting
AEG has conducted more than 60 planning studies for more than 40 utilities / organizations in the past five years.
AEG has a team of 11 experienced Planning staff plus support from AEG’s Technical Services and Program Evaluation groups
AEG EXPERIENCE IN PLANNING
Northwest & Mountain:Avista*BPA*Cascade Natural GasChelan PUDCheyenne LFPColorado Electric*Cowlitz PUD*
Inland P&L*Oregon Trail ECPacifiCorp*PNGCPGE*Seattle City Light*Tacoma Power*
Southwest:HECOLADWPNV Energy*Public Service New Mexico* State of HawaiiState of New MexicoXcel/SPS
Midwest: Ameren Illinois*Ameren Missouri*Citizens EnergyEmpire District ElectricIndianapolis P&L*Indiana & Michigan Utilities
Kansas City Power & Light MERCNIPSCO*Omaha Public Power DistrictState of MichiganVectren Energy*
Northeast & Mid Atlantic:Central Hudson G&E*Con Edison of NY*New Jersey BPUPECO EnergyPSEG Long IslandState of Maryland (BG&E, DelMarva, PEPCO, Potomac Edison, SMECO)
Regional & National:Midcontinent ISO*EEI/IEE*EPRI FERC* Two or more studies
South:OG&EKentucky PowerSouthern Company (APC,GPC, Gulf Power, MPC)TVA
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 684 of 794
AEG CPA Methodology
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 685 of 794
| 9Applied Energy Group · www.appliedenergygroup.com
The Avista Conservation Potential Assessment (CPA) supports the
Company’s regulatory filing and other demand-side management (DSM)
planning efforts and initiatives.
The two primary research objectives for the 2020 CPA are:
•Program Planning:insights into the market for natural gas energy efficiency (EE) measures in Avista’s Washington and Idaho service territories
▪For example, CPAs provide insight into changes to existing program measures as well
as new measures to consider
•IRP: long-term forecast of future EE potential for use in the IRP
▪Economic Achievable Potential (EAP) for natural gas
AEG utilizes its comprehensive LoadMAP analytical models that are
customized to Avista’s service territory.
CPA OBJECTIVES
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 686 of 794
| 10Applied Energy Group · www.appliedenergygroup.com
Overview –Natural Gas CPAOVERVIEW OF AEG’S APPROACH
Market Characterization
•Avista control totals•Customer account data•Secondary data
•Avista market research
Identify Demand-Side Resources
•EE technologies•EE measures•Emerging measures and technologies
Baseline Projection
•Avista Load Forecast•Customer growth•Standards and building codes•Efficiency options•Purchase Shares
Potential Estimation
•Technical•Technical Achievable•Economic Screen (TRC and UCT)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 687 of 794
| 11Applied Energy Group · www.appliedenergygroup.com
Prioritization of Avista Data
Data from Avista was prioritized when available, followed by regional
data, and finally well-vetted national data.
Avista sources include:
•2013 Residential GenPop Survey
•Forecast data and load research
•Recent-year accomplishments and plans
Regional sources include:
•NEEA studies (RBSA 2016, CBSA 2019, IFSA)
•RTF and Power Council methodologies, ramp rates, and measure assumptions
Additional sources include:
•U.S. DOE’s Annual Energy Outlook
•Technical Reference Manuals and California DEER
•AEG Research
KEY SOURCES OF DATA
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 688 of 794
| 12Applied Energy Group · www.appliedenergygroup.com
Overview
“How much energy would customers use in the future if Avista stopped running programs now and in the absence of naturally occurring efficiency?”
•The baseline projection answers this question
The baseline projection is an independent end-use forecast of natural gas consumption at the same level of detail as the market profile
The baseline projection:
BASELINE PROJECTION
Includes
•To the extent possible, the same forecast drivers used in
the official load forecast, particularly customer growth,
natural gas prices, normal weather, income growth, etc.
•Trends in appliance saturations, including distinctions for
new construction.
•Efficiency options available for each technology , with
share of purchases reflecting codes and standards
(current and finalized future standards)
•Expected impact of appliance standards that are “on the
books”
•Expected impact of building codes, as reflected in market
profiles for new construction
•Market baselines when present in regional planning
assumptions
Excludes
•Expected impact of naturally occurring efficiency (except
market baselines)
•Impacts of current and future demand-side management
programs
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 689 of 794
| 13Applied Energy Group · www.appliedenergygroup.com
LEVELS OF POTENTIAL
Technical
Achievable
Technical
UCT and TRC Economic
Achievable
We estimate three levels of
potential. These are standard
practice for CPAs in the Northwest:
•Technical: everyone chooses the most efficient option when
equipment fails regardless of cost
•Achievable Technical is a subset of
technical that accounts for achievable participation within utility
programs as well as non-utility
mechanisms, such as regional initiatives and market transformation
•Achievable Economic is a subset of
achievable technical potential that includes only cost-effective
measures. Tests considered within
this study include UCT, and TRC.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 690 of 794
| 14Applied Energy Group · www.appliedenergygroup.com
Two Cost-Effectiveness TestsECONOMIC SCREENING
In assessing cost-effective,
achievable potential within Avista’s
Washington and Idaho territories,
AEG utilized two cost tests:
•Utility Cost Test (UCT): Assesses cost-
effectiveness from a utility or program administrator’s perspective.
•Total Resource Cost Test (TRC):Assesses cost-effectiveness from the
utility’s and participant’s perspectives. Includes non-energy impacts if they can be quantified and
monetized.
Component UCT TRC
Avoided Energy Benefit Benefit
Non-Energy Benefits*Benefit
Incremental Cost Cost
Incentive Cost
Administrative Cost Cost Cost
Non-Energy Costs* (e.g. O&M)Cost
*Council methodology includes monetized
impacts on other fuels within these categories
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 691 of 794
| 15Applied Energy Group · www.appliedenergygroup.com
•The Measure Assumptions appendix is again available, containing UES data
and other key assumptions and their sources
•Fully Balanced TRC. Using the same process developed in the 2018 CPA, the
balanced TRC test includes an expanded scope of documentable and
quantifiable impacts, including:
1.10% Conservation Credit in Washington
2.Quantified and monetized non-energy impacts (e.g. water, detergent, wood)
3.Projected cost of carbon in Washington
4.Heating calibration credit for secondary fuels (12% for space heating, 6% for
secondary heating)
5.Electric benefits for applicable measures (e.g. cooling savings for smart thermostats,
lighting and refrigeration savings for retrocommissioning)
ENHANCEMENTS RETAINED FROM 2018
CPA
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 692 of 794
| 16Applied Energy Group · www.appliedenergygroup.com
Potential Summary –WA & ID All SectorsGAS ENERGY EFFICIENCY POTENTIAL
Projections indicate that gas
savings of 1.5% of baseline
consumption per year are
Technically Achievable, and 0.8%
per year is cost effective under
the UCT test.
•TAP savings are 643,198 Dth in
2022, and 4,906,228 Dth in 2030
•UCT savings are 261,833 Dth in
2022 and 2,124,189 Dth in 2030
•Across the study period, ~46% of
TAP savings are UCT cost-effective
-
5,000,000
10,000,000
15,000,000
20,000,000
25,000,000
30,000,000
35,000,000
40,000,000
Dth
Annual Energy Projections
Baseline Projection
Achievable Economic UCT Potential
Achievable Technical Potential
Technical Potential
0
200,000
400,000
600,000
800,000
1,000,000
1,200,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Annual Incremental Potential
Achievable Economic TRC Potential Achievable Economic UCT Potential
Achievable Technical Potential Technical Potential
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 693 of 794
| 17Applied Energy Group · www.appliedenergygroup.com
GAS EE POTENTIAL, CONTINUEDPotential Summary –WA & ID, All Sectors
-
1,000,000
2,000,000
3,000,000
4,000,000
5,000,000
6,000,000
7,000,000
2019 2022 2025 2028 2031 2034 2037 2040 2043
Cumulative UCT Gas Savings (Dth) by Sector
Residential Commercial Industrial
0.0%
10.0%
20.0%
30.0%
40.0%
50.0%
2021 2022 2025 2030 2040 2045
% of
Baseline
Cumulative Gas Savings, Selected Years
Achievable Economic TRC Potential Achievable Economic UCT Potential
Achievable Technical Potential Technical Potential
Summary of Energy Savings (Dth),
Selected Years 2021 2022 2025 2030 2040 2045
Reference Baseline 29,137,671 29,434,469 30,325,189 31,617,083 33,626,695 34,510,725
Cumulative Savings (Dth)
Achievable Economic TRC Potential 68,091 163,156 364,805 1,125,806 3,188,178 4,257,057
Achievable Economic UCT Potential 111,637 261,833 686,706 2,124,189 5,585,922 6,625,682
Achievable Technical Potential 290,015 643,198 1,879,807 4,906,228 9,853,874 10,970,898
Technical Potential 662,737 1,387,924 3,587,536 7,862,508 13,922,189 15,068,864
Energy Savings (% of Baseline)
Achievable Economic TRC Potential 0.2%0.6%1.2%3.6%9.5%12.3%
Achievable Economic UCT Potential 0.4%0.9%2.3%6.7%16.6%19.2%
Achievable Technical Potential 1.0%2.2%6.2%15.5%29.3%31.8%
Technical Potential 2.3%4.7%11.8%24.9%41.4%43.7%
Incremental Savings (Dth)
Achievable Economic TRC Potential 68,091 95,046 117,484 165,797 218,288 49,635
Achievable Economic UCT Potential 111,637 150,478 202,477 345,896 343,741 56,935
Achievable Technical Potential 290,015 355,639 522,562 701,742 483,964 58,801
Technical Potential 662,737 730,524 845,047 950,617 611,563 98,433
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 694 of 794
| 18Applied Energy Group · www.appliedenergygroup.com
Achievable Economic UCT Potential
Rank Measure / Technology
(Ranked by 1st year potential)
Achievable Economic UCT Potential (Dth)% of Total2021202220232030
1 Residential -Furnace 35,602 81,473 134,334 136,211 6.4%
2 Residential -Gas Furnace -Maintenance 13,403 30,912 48,232 177,842 8.4%
3 Commercial -Water Heater 8,854 25,070 46,662 292,125 13.8%
4 Commercial -Space Heating -Heat Recovery Ventilator 7,569 15,162 22,499 65,615 3.1%
5 Commercial -Boiler 6,643 17,112 30,155 131,730 6.2%
6 Residential -Insulation -Ceiling, Installation 5,253 11,641 19,390 99,329 4.7%
7 Residential -ENERGY STAR Connected Thermostat 4,435 9,925 16,719 114,399 5.4%
8 Commercial -HVAC -Duct Repair and Sealing 3,777 7,461 11,046 33,252 1.6%
9 Commercial -Insulation -Wall Cavity 3,337 9,043 17,710 123,408 5.8%
10 Residential -Water Heater 2,954 9,266 19,112 162,884 7.7%
11 Industrial -Process Heat Recovery 2,849 5,670 8,461 21,943 1.0%
12 Commercial -Gas Boiler -Insulate Steam Lines/Condensate
Tank 2,517 4,965 7,337 21,733 1.0%
13 Commercial -Insulation -Roof/Ceiling 2,507 6,823 13,348 89,849 4.2%
14 Commercial -Water Heater -Central Controls 1,901 3,766 5,585 13,155 0.6%
15 Commercial -Gas Boiler -Hot Water Reset 1,822 4,002 6,598 30,638 1.4%
16 Commercial -Gas Boiler -High Turndown 1,230 2,424 3,578 8,452 0.4%
17 Commercial -Fryer 1,210 2,946 5,199 29,424 1.4%
18 Commercial -Building Automation System 590 1,735 3,703 61,280 2.9%
19 Commercial -Water Heater -Faucet Aerator 581 1,269 2,079 9,046 0.4%
20 Commercial -Kitchen Hood -DCV/MUA 529 1,055 1,577 5,057 0.2%
Total of Top 20 Measures 107,565 251,718 423,324 1,627,371 76.6%
Total Cumulative Savings 111,637 261,833 445,437 2,124,189 100.0%
GAS EE TOP MEASURES
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 695 of 794
| 19Applied Energy Group · www.appliedenergygroup.com
UCT & TRC Potential vs Technical AchievableGAS EE TOP MEASURES
Rank Measure / Technology
(Ranked by 10-year TAP)
2030 Savings (Dth)% of TAP
TAP UCT TRC UCT TRC
1 Residential -Windows -High Efficiency 670,667 905 0 0.1%0.0%
2 Residential -Combined Boiler + DHW System (Storage Tank)410,862 0 0 0.0%0.0%
3 Residential -Combined Boiler + DHW System (Tankless)338,983 0 0 0.0%0.0%
4 Commercial -Water Heater 292,125 292,125 292,125 100.0%100.0%
5 Residential -ENERGY STAR Homes 198,515 198,833 0 100.2%0.0%
6 Residential -Gas Furnace -Maintenance 191,846 177,842 0 92.7%0.0%
7 Residential -Water Heater 163,124 162,884 0 99.9%0.0%
8 Residential -Insulation -Wall Cavity, Installation 162,690 8,840 0 5.4%0.0%
9 Residential -Insulation -Ceiling, Installation 145,717 99,329 0 68.2%0.0%
10 Residential -Furnace 136,211 136,211 136,211 100.0%100.0%
11 Residential -ENERGY STAR Connected Thermostat 136,197 114,399 0 84.0%0.0%
12 Commercial -Boiler 131,730 131,730 131,730 100.0%100.0%
13 Residential -Insulation -Floor/Crawlspace 128,866 56,643 0 44.0%0.0%
14 Commercial -Insulation -Wall Cavity 123,131 123,408 115,763 100.2%94.0%
15 Commercial -Water Heater -Solar System 112,885 0 0 0.0%0.0%
16 Residential -Windows -Low-e Storm Addition 108,983 0 121,262 0.0%111.3%
17 Commercial -Insulation -Roof/Ceiling 97,447 89,849 31,527 92.2%32.4%
18 Residential -Insulation -Ceiling, Upgrade 83,492 0 0 0.0%0.0%
19 Residential -Insulation -Basement Sidewall 81,620 0 0 0.0%0.0%
20 Commercial -Building Automation System 74,305 61,280 0 82.5%0.0%
Total of Top 20 Measures 3,789,395 1,654,278 828,619
Total Cumulative Savings 4,906,228 2,124,189 1,125,806 43.3%22.9%
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 696 of 794
| 20Applied Energy Group · www.appliedenergygroup.com
Comparison with Prior Potential Study (2021-2038 TAP)
•The previous CPA included potential for 2018-2020, which is removed here
•For the 2021-2038 period, the current study shows quite a bit more Technical Achievablepotential
•However, UCT Cost Effectivepotential is lower for this period.
▪Largest drop is in Residential water heating, due to a combination of factors:
•Lower Water Heater unit savings
•Removal or reduction in WA of HB-1444 affected water saving measures
•New potential from measures like combination DHW+Boiler systems is expensive
ACHIEVABLE POTENTIAL COMPARISON
Sector End Use 2038 TAP Savings (Dth)Diff.
(All States)Prior CPA Current Study
Residential
Space Heating 2,879,487 4,019,918 1,140,431
Secondary Heating 62,068 37,249 -24,819
Water Heating 2,264,651 2,382,341 117,690
Appliances 3,455 21,880 18,425
Miscellaneous 2,682 3,172 490
Commercial
Space Heating 1,328,855 1,523,386 194,530
Water Heating 268,621 903,545 634,924
Food Preparation 136,388 139,204 2,816
Miscellaneous 51 173 122
Industrial
Space Heating 7,145 8,125 980
Process 15,435 40,310 24,875
Miscellaneous 369 0 -369
Grant Total 6,969,208 9,079,303 2,110,095
Sector End Use 2038 UCTSavings (Dth)Diff.(All States)Prior CPA Current Study
Residential
Space Heating 2,274,729 2,071,662 -203,067
Secondary Heating 0 0 0
Water Heating 2,223,975 943,071 -1,280,904
Appliances 1,258 0 -1,258
Miscellaneous 0 0 0
Commercial
Space Heating 1,131,121 1,088,143 -42,978
Water Heating 135,582 638,616 503,033
Food Preparation 136,388 139,204 2,816
Miscellaneous 45 148 103
Industrial
Space Heating 1,747 6,906 5,159
Process 14,367 34,395 20,028
Miscellaneous 369 0 -369
Grant Total 5,919,582 4,922,145 -997,437
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 697 of 794
| 21Applied Energy Group · www.appliedenergygroup.com
2030 Savings (TAP) by UCT Cost Bundle –WA + ID All Sectors
0
100,000
200,000
300,000
400,000
500,000
600,000
700,000
Dth
UCT $/therm
2030 TAP Savings by Cost Bundle
ACHIEVABLE POTENTIAL
UCT $/Therm
2030 TAP
Savings (Dth)
$0.00 -$0.10 616,956
$0.10 -$0.20 213,315
$0.20 -$0.30 371,273
$0.30 -$0.40 146,027
$0.40 -$0.50 431,922
$0.50 -$0.60 219,860
$0.60 -$0.70 132,429
$0.70 -$0.80 222,526
$0.80 -$0.90 184,609
$0.90 -$1.00 55,730
$1.00 -$1.10 94,636
$1.10 -$1.20 91,213
$1.20 -$1.30 140,536
$1.30 -$1.40 215,089
$1.40 -$1.50 111,421
$1.50 -$1.60 109,370
$1.60 -$1.70 228,011
$1.70 -$1.80 158,836
$1.80 -$1.90 625,317
$1.90 -$2.00 54,020
$2 or more 483,133
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 698 of 794
THANK YOU!
Ingrid Rohmund, Sr. Vice President, [e-mail]
Ken Walter, Project Manager
[e-mail]
Kelly Marrin, Managing Director
[e-mail]
Tommy Williams, Lead Analyst
[e-mail]
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 699 of 794
Energy Trust of Oregon
Energy Efficiency Resource Assessment Study
November 18, 2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 700 of 794
Agenda
•About Energy Trust
•2019 Achieved Savings
•Resource Assessment
Overview and Background
•Methodology
•Results
•Questions/Discussion
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 701 of 794
Independent nonprofit
Providing access to affordable energy
Generating homegrown, renewable power
Serving 1.6 million customers of Portland General Electric, Pacific Power, NW Natural, Cascade Natural Gas and Avista
Building a stronger Oregon and SW Washington
About us
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 702 of 794
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 703 of 794
Nearly 660,000
sites
transformed
into energy
efficient,
healthy,
comfortable
and productive
homes and
businesses
From Energy Trust’s investment of $1.5 billion in utility customer
funds:
10,000 clean
energy
systems
generating
renewable
power from the
sun, wind,
water,
geothermal
heat and
biopower
$6.9 billion in
savings over
time on
participant utility
bills
from their
energy-
efficiency and
solar
investments
20 million tons
of carbon
dioxide
emissions kept
out of our air,
equal to
removing 3.5
million cars from
our roads
for a year
15 years of affordable energy
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 704 of 794
607 average megawatts saved
121 aMW generated
52 million annual therms saved
Enough energy to power 564,000 homes
and heat 100,000 homes for a year
Avoided 20 million tons of carbon dioxide
A clean energy power plant
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 705 of 794
Energy Trust’s 2019 Achievements for Avista
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 706 of 794
Energy Trust Savings
Achievements –2019
•Energy Trust began serving Avista customers in Oregon
in 2016.
•Overall achieved 107% of goal
•Goal 360k Therms
•Achieved 384k Therms
•Anticipate continued success
as we solidify trade ally and customers relationships.
Energy Trust achieved 107% of goal in Avista service territory
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 707 of 794
Resource Assessment:
Purpose, Overview and Background
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 708 of 794
Resource Assessment (RA)
Purpose
•Provides estimates of energy efficiency potential that will result in a
reduction of load on Avista’s system
for use in Avista’s Integrated Resource Plan (IRP).
•The purpose is to help Avista strategically plan future investment in
both supply side and demand side
resources.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 709 of 794
Resource Assessment Overview
•W hat is a resource assessment?
•Model that provides an estimate of energy efficiency resource potential achievable over a 20-year period
•‘Bottom-up’ approach to estimate potential starting at the measure level and scaling to a service territory
•Energy Trust uses a model in Analytica that was
developed by Navigant Consulting
•The Analytica model calculates Technical, Achievable and Cost-Effective Achievable Energy Efficiency Potential.
•Final program/IRP targets are established via ramp rates that are applied outside of the model.
•Data inputs and assumptions in the model are updated in
conjunction with IRP about every two years.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 710 of 794
Additional Resource Assessment
Background
•Informs utility IRP work & Energy Trust strategic and
program planning.
•Does not specify mechanism of savings acquisition (e.g. programs, market transformation, codes & standards)
•Does not dictate source or measure mix of annual energy savings acquired by programs
•Does not set incentive levels
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 711 of 794
20-Year Forecast Methodology
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 712 of 794
Not
Technically
Feasible
Technical Potential
Calculated
within RA
Model
Market
Barriers
Achievable Potential
Not Cost-
Effective
Cost-Effective Achievable
Potential
Program Design &
Market Penetration
Final Program
Savings
Potential
Developed
with
Programs
& Market
Information
Forecasted Potential Types
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 713 of 794
20-Year IRP EE Forecast Flow Chart
Technical potential is reduced due to market barriers
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 714 of 794
RA Model inputs
Measure Inputs
Measure Definition:
•Baseline & Efficient equipment
•Applicable customer segments
•Installation type*
•Measure Life
Measure Savings
Measure Cost
•Incremental cost for lost opportunity
measures
•Full cost for retrofit measures
Market Data
•Density
•Saturation of baseline equipment
•Technical suitability
Utility Inputs
Customer and Load Forecasts
Used to scale measure level savings
to a service territory
•Residential Stock: Count of homes
•Commercial Stock: Floor Area
•Industrial Stock: Customer load
Avoided Costs
Customer Stock Demographics:
•Heating fuel splits
•Water heat fuel splits
*Retrofit, Replace on Burnout, or New
Construction
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 715 of 794
Model Updates
•The RA Model is a ‘living’ model and Energy Trust makes continuous improvements to it.
•Measure updates, new measures and new emerging technologies updated in model
•Alignment with high-level NW Power Council Power Plan
deployment methodologies to obtain cost-effective
achievable savings within market sectors and
replacement types.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 716 of 794
Key Measure Inputs:
•Baseline: 0.60 EF gas water heater
•Replacement Type: Replacement on Burnout / New
•Measure Incremental Cost: $218
•Conventional (not emerging, no risk adjustment)
•Lifetime:13 years
•Savings: 31.6 therms (annual)
•Non-Energy Benefits: $5.34 per year
•Customer Segments: SF, MF, MH
•Density, Saturation, Suitability
•Competing Measures: All efficient gas water heaters
Example Measure: Residential Gas Tank
Water Heater (>0.70 EF)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 717 of 794
Incremental Measure Savings Approach
(Competition group: Gas water heaters)
En
e
r
g
y

S
a
v
i
n
g
s

(
T
h
e
r
m
s
)
EF = 0.67 EF > 0.70
En
e
r
g
y

S
a
v
i
n
g
s

(
T
h
e
r
m
s
)
EF = 0.67 EF > 0.70
TRC 1.5
(Numbers are
for illustrative
purposes
only)TRC 1.1 Inc. SavingsAll Savings
Savings potential
for competing
technologies are
incremental to one
another based on
relative TRCs
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 718 of 794
•Energy Trust utilizes the Total Resource Cost (TRC) test
to screen measures for cost effectiveness
•If TRC is > 1.0, it is cost-effective
•Measure Benefits:
•Avoided Costs (provided by Avista)
•Annual measure savings x NPV avoided costs per therm
•Quantifiable Non-Energy Benefits
•Water savings, etc.
Total Measure Cost:
•The total cost of the EE measure (full cost if retrofit, incremental over baseline if replacement)
Cost-Effectiveness Screen
TRC =𝑴𝒆𝒂𝒔𝒖𝒓𝒆𝑩𝒆𝒏𝒆𝒇𝒊𝒕𝒔
𝑻𝒐𝒕𝒂𝒍𝑴𝒆𝒂𝒔𝒖𝒓𝒆𝑪𝒐𝒔𝒕
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 719 of 794
Cost-Effectiveness Override
Energy Trust applied this to measures found
to be NOT Cost-Effective in the model but are offered through Energy Trust programs.
Reasons:
1.Blended avoided costs may produce
different results than utility specific avoided costs
2.Measures offered under an OPUC exception per UM 551 criteria.
The following measures had the CE override applied (all under OPUC exception):
•Com Clothes Washers
•Res Insulation (ceiling, floor, wall)
•Res Clothes Dryers
•Res New Homes Packages
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 720 of 794
Emerging Technologies
•Model includes savings potential from emerging technologies
•Factors in changing performance, cost over time
•Use risk factors to hedge against uncertainty
Residential Commercial Industrial
• Path 5 Emerging Super
Efficient Whole Home
• DOAS/HRV -GAS
Space Heat
• Gas-fired HP Water
Heater
• Window Replacement
(U<.20), Gas SF • Gas-fired HP HW
• Wall Insulation-VIP,
R0-R35
• Absorption Gas Heat
Pump Water Heaters • Gas-fired HP, Heating
• Advanced Insulation • Advanced Windows
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 721 of 794
Risk Factors for Emerging Technologies
Risk Category 10%30%50%70%90%
Market Risk(25% weighting)
Requires new/changed
business model
Start-up, or small manufacturer
Significant changes to
infrastructure
Requires training of
contractors. Consumer acceptance barriers exist.
Training for
contractors
available.
Multiple
products in
the market.
Trained contractors
Established business models
Already in U.S. Market
Manufacturer committed to
commercialization
Technical Risk
(25%
weighting)
Prototype in first
field tests.
A single or
unknown
approach
Low volume
manufacturer.
Limited
experience
New product
with broad
commercial
appeal
Proven technology in
different application
or different region
Proven
technology in
target
application.
Multiple
potentially
viable
approaches.
Data Source
Risk
(50%
weighting)
Based only on
manufacturer claims
Manufacturer case studies Engineering
assessment or lab test
Third party case study
(real world installation)
Evaluation
results or
multiple third
party case studies
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 722 of 794
Results
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 723 of 794
Not
Technically
Feasible
Technical Potential
Calculated
within RA
Model
Market
Barriers
Achievable Potential
Not Cost-
Effective
Cost-Effective Achievable
Potential
Program Design
& Market
Penetration
Final
Program
Savings
Potential
Developed
with
Programs
& Other
Market
Information
The RA Model estimates the in Technical, Achievable and Cost-Effective
Achievable potential
Final Program Savings Potential is deployed exogenously of the model using
the Cost-Effective Achievable potential from the RA model in combination with
program expertise on what can be achieved
Outputs of Potential Type
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 724 of 794
Overall Cumulative Savings Results
0
5
10
15
20
25
30
Technical Potential Achievable
Potential
Cost-Effective
Achievable
Potential
Energy Trust
Savings Projection
Mi
l
l
i
o
n
s

o
f

T
h
e
r
m
s
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 725 of 794
RA Model Results
Technical, Achievable, and Cost-Effective Achievable
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 726 of 794
Cumulative Potential by Type and Year
0
5
10
15
20
25
30
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039
Mi
l
l
i
o
n
s

o
f

T
h
e
r
m
s

Technical Achievable Cost-Effective Achievable
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 727 of 794
Contribution of Emerging Technology
24%
23%
20%
0
5
10
15
20
25
30
Technical Achievable Cost-effective
Achievable
20
-Ye
a
r

P
o
t
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n
t
i
a
l

(
M
i
l
l
i
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n
s

o
f

T
h
e
r
m
s
)
Conventional Emerging
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 728 of 794
Cumulative Potential by Sector and Type
-
2
4
6
8
10
12
14
16
18
Residential Commercial Industrial
Mi
l
l
i
o
n
s

o
f

T
h
e
r
m
s
Technical Achievable Cost-effective Achievable
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 729 of 794
Cost-effective Achievable Potential by End
Use
0.03 0.04 0.16 0.33 0.42
0.56
0.71
4.80
5.14
5.78
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 730 of 794
Cost-Effective Override Effect –(Millions of
Therms)
Sector
Potential
with
Override
Potential
without
Override
Difference
Residential 12.1 10.9 1.2
Commercial 5.7 5.7 0.0
Industrial 0.2 0.2 0.0
Total 18.0 16.8 1.2
Measures with CE Override in Model:
•Res Insulation (ceiling, floor, wall)
•Res Clothes Dryers
•Res New Homes Packages
•Com Clothes Washers
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 731 of 794
Top-20 Measures
- 0.2 0.4 0.6 0.8 1.0 1.2 1.4
Res 0.7 EF Tank Water Heater
Com Wifi Thermostat
Com DHW Pipe Insulation
Res Window Replacement (U=0.3)
Com Gas Absorption HPWH
Res Attic Insulation
Res Floor Insulation
Res Wall Insulation
Com Demand Control Ventillation
Com DOAS/HRV
Com New Construction
Com Strategic Energy Management
Res Path 3 New Home
Res Path 4 New Home
Res Gas Furnace
New Home Market Transformation
Res Window Replacement (U<0.2)
Res Path 2 New Home
Res Gas Absorption HPWH
Res Smart Thermostat
Cumulative Cost-Effective Achievable Potential (Millions of Therms)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 732 of 794
Final Savings Projections -
Deployed Results
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 733 of 794
Energy Trust sets the first five years of energy efficiency acquisition to program performance and budget goals.
Final Savings Projection Methodology
Years 1-2
•Program forecasts –they know what is happening short term best
Years 3-5
•Planning and Programs work together to create forecast
Years 6-20
•Planning forecasts long-term acquisition rate to generally align NWPCC
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 734 of 794
Cumulative Potential by Type –Millions of
Therms
Technical
Potential
Achievable
Potential
Cost-
Effective
Achievable
Potential
Energy Trust
Savings
Projection
Residential 16.9 15.2 12.1 8.2
Commercial 7.8 6.8 5.7 6.1
Industrial 0.3 0.2 0.2 0.5
All Sectors 24.9 22.2 18.0 14.8
Not all Cost-Effective Potential is projected to be achieved because:
•Lost opportunity with ‘Replacement’ and ‘New Constr.’ measures
•Hard to reach measures (e.g. insulation)
•Other market barriers identified by programs & new service territory
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 735 of 794
Cost-Effective Savings
Heating
Water Heating
Weatherization
-
0.2
0.4
0.6
0.8
1.0
1.2
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039
Mi
l
l
i
o
n
s

o
f

T
h
e
r
m
s
Large Project Adder
Weatherization
Water Heating
Ventilation
Process Heating
Other
Heating
Cooking
Behavioral
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 736 of 794
Projected Savings as Percent of Annual Load
0%
2%
4%
6%
8%
10%
12%
14%
16%
0.0%
0.2%
0.4%
0.6%
0.8%
1.0%
1.2%
Cu
m
u
l
a
t
i
v
e

S
a
v
i
n
g
s

a
s

%

o
f

L
o
a
d
An
n
u
a
l

S
a
v
i
n
g
s

a
s

%

o
f

A
n
n
u
a
l

L
o
a
d

Annual Cumulative
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 737 of 794
Levelized Cost Supply Curve
-
5
10
15
20
25
-$5 -$3 -$1 $1 $3 $5 $7 $9
Cu
m
u
l
a
t
i
v
e

2
0
-Ye
a
r

P
o
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e
n
t
i
a
l

(
M
i
l
l
i
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n
s

o
f

T
h
e
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m
s
)
Levelived Cost ($/therm)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 738 of 794
Benefit Cost Ratio Supply Curve
-
5
10
15
20
25
- 1 2 3 4 5 6 7 8 9 10
Cu
m
u
l
a
t
i
v
e

2
0
-Ye
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P
o
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l

(
M
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i
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s

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f

T
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s
)
Total Resource Cost Benefit-Cost Ratio
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 739 of 794
Thank you
Spencer Moersfelder,
Planning Manager
[e-mail]
503.548.1596
Ted Light,
Lighthouse Energy Consulting
[e-mail]
503.395.5310
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 740 of 794
6868
Sendout Model
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 741 of 794
69696969
Modeling Transportation In SENDOUT®
•Start with a point-in-time look at each jurisdiction’s resources
•Contracts –Receipt and Delivery Points
•Rates
•Contractual vs. Operational
•Contractual can be overly restrictive
•Operational can be overly flexible
•Incorporating operational realities into our modeling can defer
the need to acquire new resources
•Gas Supply’s job is to get gas from the supply basin to the
pipeline citygate
•Gas Engineering/Distribution’s job is to take gas from the
pipeline citygate to our customers
•The major limiting factor is receipt quantity –how much can you
bring into the system?
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 742 of 794
707070
Modeling Challenges
•Supply needs to get gas to the gate
•Contracts were created years ago, based on demand projections at that
point in time
•Stuff happens (i.e. growth differs from forecast)
•Sum of receipt quantity and aggregated delivery quantity don’t identify
resource deficiency for quite some time however…..
•The aggregated look can mask individual city gate issues, and the
disaggregated look can create deficiencies where they don’t exist
•In many cases, operational capacity is greater than contracted
•Transportation resources are interconnected (two pipes can serve one
area)
•WARNING –we need to be mindful of the modeling limitations
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 743 of 794
71717171
What is in SENDOUT®?
Inside:
•Demand forecasts at an aggregated level
•Existing firm transportation resources and current
rates
•Receipt point to aggregated delivery
points/“zone”
•Jurisdictional considerations
•Long term capacity releases
•Potential resources, both supply and demand side
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 744 of 794
72727272
What is outside SENDOUT®?
Outside:
•Gate station analysis
•Forecasted demand behind the gate
•Growth rates consistent with IRP assumptions
•Actual hourly/daily city gate flow data
•Gate station MDDO’s
•Gate station operational capacities
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 745 of 794
737373
Supply Interconnect Demand
Transport
Storage
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 746 of 794
74747474
New Planning Software
•Avista is looking for a new software solution to
model our natural gas system and the
increasingly complex system with carbon
reduction goals
•We hope to have this software available for the
next round of Integrated Resource Planning
(IRP) and to model it in parallel with Sendout
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 747 of 794
7575
Assumptions Review
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 748 of 794
76767676
Firm Customers (Meters) by State and Class, 2019
WA
47%
ID
24%
OR
29%
Firm Customers by State
Residential
90%
Commercial
10%
Industrial
0.1%
Firm Customers by Class
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 749 of 794
77777777
WA-ID Region Firm Customer Range, 2021-2045
220,000
240,000
260,000
280,000
300,000
320,000
340,000
360,000
380,000
400,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
WAIDFIRMCUS Base WAIDFIRMCUS High WAIDFIRMCUS Low
Variable Low
Growth
Base
Growth
High
Growth
WA-ID Customers 0.7%1.1%1.5%
WA Population 0.4%0.7%1.0%
ID Population 0.8%1.4%2.0%
WA-ID Population 0.5%0.8%1.2%
77
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 750 of 794
78787878
OR Region Firm Customer Range, 2021-2045
95,000
100,000
105,000
110,000
115,000
120,000
125,000
130,000
135,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
ORFIRMCUS Base ORFIRMCUS High ORFIRMCUS Low
Variable Low
Growth
Base
Growth
High
Growth
Customers 0.5%0.7%0.9%
Population 0.3%0.5%0.7%
78
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 751 of 794
79797979
System Firm Customer Range, 2021-2045
300,000
350,000
400,000
450,000
500,000
550,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
SYSTEMCUS.syf Base SYSTEMCUS.syf High SYSTEMCUS.syf Low
Variable Low
Growth
Base
Growth
High
Growth
Customers 0.6%1.0%1.3%
Population 0.4%0.8%1.1%
79
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 752 of 794
80808080
Summary of Growth Rates
System Base-Case High Low
Residential 1.0%1.4%0.7%
Commercial 0.5%0.8%0.1%
Industrial -0.8%2.2%-3.8%
Total 1.0%1.3%0.6%
WA Base-Case High Low
Residential 1.0%1.3%0.7%
Commercial 0.4%0.7%0.1%
Industrial -0.8%1.9%-3.6%
Total 1.0%1.3%0.7%
ID Base-Case High Low
Residential 1.4%2.0%0.8%
Commercial 0.4%1.0%-0.2%
Industrial -1.0%1.8%-3.4%
Total 1.3%1.9%0.7%
OR Base-Case High Low
Residential 0.7%0.9%0.5%
Commercial 0.6%0.8%0.4%
Industrial 0.0%4.5%-10.6%
Total 0.7%0.9%0.5%
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 753 of 794
818181
Base Coefficients (July and August
Averaged)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 754 of 794
828282
Heat Coefficients
Planning Area -Residential Class 2 Year 3 Year 5 Year
Roseburg (Oregon)0.008829 0.008046 0.00699
Medford (Oregon)0.00639 0.0065 0.006068
La Grande (Oregon)0.006223 0.007297 0.00665
Klamath Falls (Oregon)0.005284 0.005268 0.004902
Idaho 0.006445 0.006344 0.005896
Washington 0.006307 0.006313 0.005957
*Avg. of monthly heat coefficient
*Historic Data –adjusted by price elasticity and DSM
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 755 of 794
83838383
Price Elasticity
•The elasticity as measured in the Medford and
Roseburg areas will be used for the entire
system as estimated elasticity.
•0.81% decrease only for each price rise of 10%
•This elasticity is measured through heat
coefficients and annual price changes
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 756 of 794
84848484
Avista Weather Planning Standard
•Utilize coldest day for each of the past 30 years
with a 99% probability supply can be fulfilled
Area 99% Probability Avg.
Temp
La Grande -11
Klamath Falls -9
Medford 11
Roseburg 14
Spokane -12
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 757 of 794
85858585
Henry Hub Expected Price and Average
Annual Price Forecasts
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 758 of 794
86868686
Stochastic Prices (Results from 1000
Draws)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 759 of 794
878787
2020 Henry Hub Prices -Nominal
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 760 of 794
88888888
Prices by Gas Hub (Henry Hub Expected
Price + Basis
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 761 of 794
89898989
Expected Case
Cost of Carbon by State -Summary
•W ashington -Social cost of carbon @ 2.5%
discount rate;
–upstream emissions associated with natural gas drilling and transportation of natural gas to
its end use.
•Oregon is based off a Wood Mackenzie
estimate for Cap and Trade
•Idaho -carbon prices will not be included
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 762 of 794
90909090
Carbon Costs
$-
$50
$100
$150
$200
$250
$300
$350
$400
$450
OR Cap and Trade WA SCC High Carbon Price Low Carbon Price
$44.92 $113.75 $234.45 $0Levelized
Cost per
MTCO2e
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 763 of 794
91919191
Carbon Costs
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 764 of 794
92929292
LDC Upstream Emissions
*Avista gas purchases
An average of the total volume purchased over
the past 5 years by emissions location
Combustion Lbs. GHG/MMBtu Lbs. CO2e/Mmbtu
CO2 116.88 116.88
CH4 0.0022 0.0748
N2O 0.0022 0.6556
Total Combustion 117.61
Upstream
CH4 0.313406851 10.66
Total 128.27
Upstream Emissions Avista's Purchases Emissions Location
0.77 89.72% Canada
1.00 10.28% Rockies
0.79
Avista Specific Natural Gas
34 GWP
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 765 of 794
939393
Avoided Cost Comparison
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 766 of 794
949494
DSM
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 767 of 794
9595
Expected Case
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 768 of 794
969696
Safe Harbor Statement
This document contains forward-looking statements.Such statements are
subject to a variety of risks,uncertainties and other factors,most of which
are beyond the Company’s control,and many of which could have a
significant impact on the Company’s operations,results of operations and
financial condition,and could cause actual results to differ materially from
those anticipated.
For a further discussion of these factors and other important factors,please
refer to the Company’s reports filed with the Securities and Exchange
Commission.The forward-looking statements contained in this document
speak only as of the date hereof.The Company undertakes no obligation to
update any forward-looking statement or statements to reflect events or
circumstances that occur after the date on which such statement is made or
to reflect the occurrence of unanticipated events.New risks,uncertainties
and other factors emerge from time to time,and it is not possible for
management to predict all of such factors,nor can it assess the impact of
each such factor on the Company’s business or the extent to which any
such factor,or combination of factors,may cause actual results to differ
materially from those contained in any forward-looking statement.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 769 of 794
97979797
Proposed Scenarios
*1,000 Draws per scenario will be run stochastically
Proposed Scenarios Expected Average Low Growth High Growth
INPUT ASSUMPTIONS Case Case & High Prices & Low Prices
Customer Growth Rate Low Growth Rate Reference Case Cust Growth Rates High Growth Rate
Demand Side Management High Prices DSM
Weather Planning Standard
99% probability of coldest
in 30 years 20 year average
GWP
Prices
Price curve
SCC @ 2.5% WA; Cap and Trade
forecast - OR;
NO Carbon adder in ID
RESULTS
First Gas Year Unserved
Washington
Idaho
Medford
Roseburg
Klamath
La Grande
Scenario Summary
Most aggressive peak
planning case utilizing
Average Case
assumptions as a starting
point and layering in peak
day 99% probability. The
likelihood of occurrence is
low.
Case most
representative of our
average (budget,
PGA, rate case)
planning criteria.
Stagnant growth
assumptions in order
to evaluate if a
shortage does occur.
Not likely to occur.
Reduction of the use of natural gas to 80%
below 1990 targets in OR and WA by
2050. The case assumes the overall
reduction is an average goal before
applying figures like elasticity and DSM.
Aggressive growth
assumptions in order
to evaluate when our
earliest resource
shortage could occur.
Not likely to occur.
Carbon Reduction
Carbon Cost - High
(SCC 95% at 3%)
SCC @ 2.5% WA; Cap and Trade forecast -
OR;
Reference Case Cust Growth Rates
LowExpectedHigh
Carbon Legislation
($/Metric Ton)
Use per Customer
100-Year GWP
NO Carbon adder in ID
3 yr + Price Elasticity
99% probability of coldest in 30 years
$0
Expected Case CPA Low Prices DSM
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 770 of 794
98989898
Existing Resources vs. Peak Day Demand
Expected Case –Washington/Idaho (DRAFT)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 771 of 794
99999999
Existing Resources vs. Peak Day Demand
Expected Case –Medford/Roseburg (DRAFT)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 772 of 794
100100100100
Existing Resources vs. Peak Day Demand
Expected Case –Klamath Falls (DRAFT)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 773 of 794
101101101101
Existing Resources vs. Peak Day Demand
Expected Case –La Grande (DRAFT)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 774 of 794
102102102102
Expected Case -Emissions
0
5
10
15
20
25
30
35
40
45
1.95
2.00
2.05
2.10
2.15
2.20
2.25
2.30
2.35
2.40
2.45
2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040
Mi
l
l
i
o
n

D
t
h
Mi
l
l
i
o
n

M
e
t
r
i
c

T
o
n
s

o
f

C
O
2
e
ID WA OR System Emissions
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 775 of 794
103103103
Expected Case Costs
33
34
35
36
37
38
39
40
41
42
43
$-
$100
$200
$300
$400
$500
$600
Mi
l
l
o
n
s
of

Dt
h
Mi
l
l
i
o
n
s
All Other Costs System Demand
$3B$3.9B
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 776 of 794
104104104
Expected Case distribution
*1000 Simulations
Average $ 6.876
Std Dev $ 1.610
Min $ 4.482
Max $ 17.713
Median $ 6.455
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 777 of 794
105105105
$0
$100
$200
$300
$400
$500
$600
$700
$800
$900
Mi
l
l
i
o
n
s
Std Dev 95th 10th Deterministic
Expected Case
1,000 Draws
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 778 of 794
106106
Other Scenarios
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 779 of 794
107107107107
Energy Demand
0
5
10
15
20
25
30
35
40
45
50
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
En
e
r
g
y

D
e
m
a
n
d
Million Dth
Carbon Reduction Average Case Expected Case Low Growth High Growth
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 780 of 794
108108108108
Emissions
*Emissions assume carbon intensity of the supply resources
2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040
Carbon Reduction 1,966 1,895 1,918 1,894 1,842 1,784 1,729 1,701 1,709 1,669 1,629 1,600 1,549 1,509 1,468 1,440 1,446 1,406 1,366 1,338
Average Case 2,011 1,868 1,883 1,913 1,921 1,929 1,938 1,961 1,968 1,984 1,999 2,023 2,030 2,045 2,061 2,086 2,093 2,109 2,124 2,149
Expected Case 2,132 2,117 2,138 2,181 2,178 2,178 2,178 2,214 2,214 2,232 2,249 2,284 2,283 2,301 2,319 2,356 2,355 2,372 2,389 2,426
Low Growth 1,820 1,237 1,237 1,251 1,249 1,255 1,260 1,274 1,271 1,276 1,282 1,295 1,292 1,297 1,301 1,315 1,311 1,316 1,321 1,334
High Growth 2,175 2,207 2,243 2,301 2,313 2,326 2,338 2,389 2,400 2,430 2,459 2,509 2,512 2,530 2,559 2,609 2,616 2,644 2,672 2,723
1.0
1.2
1.4
1.6
1.8
2.0
2.2
2.4
2.6
2.8
3.0
Mi
l
l
i
o
n

M
T
C
O
2
e
Carbon Reduction Average Case Expected Case Low Growth High Growth
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 781 of 794
109109109109
Average Case
Average 5.69$
Min 5.50$
Max 6.12$
Std Dev 0.05$
Median 5.69$
*Billions ($)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 782 of 794
110110110110
Low Growth and High Prices
Average 9.80$
Min 9.60$
Max 10.01$
Std Dev 0.06$
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 783 of 794
111111111
#
o
f

2
0

y
e
a
r

f
u
t
u
r
e
s
Solve - No Unserved Average Stdev Median Max Min
RNG Resources Only 2.683$ 0.043$ 2.681$ 2.861$ 2.542$
Plymouth, RNG in La Grande 2.721$ 0.043$ 2.719$ 2.901$ 2.580$
GTN - RNG in La Grande 2.734$ 0.042$ 2.675$ 2.855$ 2.540$
Medford Lateral Expansion,
RNG in La Grande 2.734$ 0.044$ 2.731$ 2.915$ 2.600$
*$ in Billions
**1,000 draws each scenario
High Growth & Low Prices
Least Cost/Risk -RNG solve
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 784 of 794
112112112112
Carbon Reduction Scenario
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 785 of 794
113113113113
Carbon Reduction scenario
•Carbon reduction goals to meet 2035 targets of 45% below 1990
emissions and criteria are not known
•Any actual availability of physical RNG resources and rate impact by
year can be further studied in future Integrated Resource Plans
•Actual projects will be considered on an ad-hoc basis to determine
costs and environmental attributes which may make different RNG
types a least cost solution
•Exact 1990 emissions are not known and are estimated based on
prior 10k’s
•Many of the rules from EO 20-04 will be coming out after this IRP is
submitted
•Allowances are not considered
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 786 of 794
114114114114
Resources Considered
*Prices include carbon intensity, carbon costs, capital and overhead, and electricity and are
considered Avista owned and operated
**Estimates are from a Black and Veach study
Resource Dth per year
Levelized Cost Per
Dth (Year 1)
Distributed Renewable Hydrogen Production -WA 60,509 $47.25
Distributed Renewable Hydrogen Production -OR 60,509 $48.01
Distributed LFG to RNG Production -WA 231,790 $15.90
Centralized LFG to RNG Production -WA 662,256 $14.11
Dairy Manure to RNG Production -WA 231,790 $14.30
Wastewater Sludge to RNG Production -WA 187,245 $23.34
Food Waste to RNG Production -WA 108,799 $33.14
Distributed LFG to RNG Production -OR 231,790 $14.34
Centralized LFG to RNG Production -OR 662,256 $12.54
Dairy Manure to RNG Production -OR 231,790 $30.59
Wastewater Sludge to RNG Production -OR 187,245 $20.36
Food Waste to RNG Production -OR 108,799 $37.46
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 787 of 794
115115115
Carbon Intensity
Source
Current Carbon
Intensity
(g CO2e/MJ)
Percent of estimated Carbon
reduction as compared to
natural gas
(as base value)
lbs. per
Dth
Natural Gas 78.37 128.27
Landfill 46.42 41%75.98
Dairy -276.24 -452%(580.40)
WWT 19.34 75%31.65
Solid Waste -22.93 -129%(165.80)
*Green H2 is considered to have no carbon or -128.27 lbs. per
Dth as compared to Natural Gas
Source: California Air Resources Board
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 788 of 794
116116116
Climate Goals
-
0.50
1.00
1.50
2.00
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
Mi
l
l
i
o
n
s

o
f

M
T
C
O
2
e
WA and OR Emissions Only
Expected Emissions MTCO2e Emissions with Climate Goals and EO
-
5
10
15
20
25
30
35
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
Mi
l
l
i
o
n
s

o
f

Dt
h
WA and OR only
Dairy Fossil Fuels
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 789 of 794
117117117
$0
$10
$20
$30
$40
$50
$60
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
Mi
l
l
i
o
n
s
Estimated Dairy Costs
Resources Needed
Levelized Cost of $29M per year
-
500,000
1,000,000
1,500,000
2,000,000
2,500,000
3,000,000
3,500,000
4,000,000
4,500,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
Dt
h
Dairy #1 Dairy #2 Dairy #3 Dairy #4 Dairy #5 Dairy #6
Dairy #7 Dairy #8 Dairy #9 Dairy #10 Dairy #11 Dairy #12
Dairy #13 Dairy #14 Dairy #15 Dairy #16 Dairy #17 Dairy #18
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 790 of 794
118118118
Carbon Reduction
Average 5.695$
Min 5.857$
Max 5.542$
Std Dev 0.048$
Median 5.695$
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 791 of 794
119119119119
Carbon Reduction Summary
•Dairy
–With a high carbon intensity and it’s ability to reduce emissions dairy becomes
the preferred resource in this IRP to reduce carbon
–As the cost of carbon gets higher dairy becomes more economic as the carbon
intensity combined with the SCC creates a low price
–Unlike some other RNG resources a dairy farm has the potential to be
reproduced unlike a landfill or waste water treatment plants
•Hydrogen
–If the high carbon offset of dairy can be mitigated with a lower price of H2 this is
both the primary and viable path
–Green H2 has a large potential to offset emissions and provide the amount of
energy demand forecasted
•Carbon offsets through allowances and the associated costs need to be considered
to fully understand least cost and least risk
•Other RNG type programs will be modeled at a detailed level as projects are
available and depending on costs and offsets could change least cost and least risk
solution
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 792 of 794
120120120120
Action Plan
•Further model carbon reduction
•Investigate new resource plan modeling software and integrate Avista’s system into
software to run in parallel with Sendout
•Model all requirements as directed in Executive Order 20-04
•Avista will ensure Energy Trust (ETO) has sufficient funding to acquire therm savings
of the amount identified and approved by the Energy Trust Board
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 793 of 794
121121121121
Next Steps
2020 Natural Gas IRP Draft Timeline
The following is Avista’s tentative 2020 Natural Gas IRP timeline:
•June -November 2020 –Technical Advisory Committee meetings
•December 2020 –Prepare draft of IRP
•January 4, 2021 –Draft of IRP document sent to TAC
•February 1, 2021 –Comments on draft due back to Avista
•February 2021 –TAC final review meeting (if necessary)
•March 2021 –Final editing and printing of IRP
•April 1, 2021 –File IRP submission to Commissions and TAC
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 3a, Page 794 of 794
Business Case Name Page Number
Generation and Environmental
1 Cabinet Gorge Dam Fishwa 2
2 Clark Fork Settlement Agreement 11
3 Right-of-Way Use Permit 17
4 Spokane River License Implementation 26
5 Base Load Thermal Program 33
6 Noxon Rapids HVAC 42
7 Peaking Generation Business Case 49
8 Asset Monitoring Syste 57
9 Base Load Hydro 62
10 Cabinet Gorge HVAC Replacement 70
11 Cabinet Gorge Station Service 78
12 Cabinet Gorge Stop Log Replacement 84
13 Cabinet Gorge Unit 1 Governor Upgrade 93
14 Cabinet Gorge Unwatering Pumps 99
15 Generation DC Supplied System Update 105
16 HMI Control Software 112
17 KF 4160 V Station Service Replacement 120
18 KF D10R Dozer Certified Power Train Rebuil 127
19 KF Secondary Superheater Replacement 134
20 KF_Fuel Yard Equipment Replacement 144
21 KF_ID Fan & Motor Replacemen 156
22 Little Falls Crane Pad & Barge Landin 165
23 Little Falls Plant Upgrade 171
24 Long Lake Plant Upgrad 178
25 Monroe Street Abandoned Penstock Stabilization 188
26 Nine Mile HED Battery Building 196
27 Nine Mile Powerhouse Crane Rehab 205
28 Nine Mile Powerhouse Roof Replacement 213
29 Nine Mile Unit 3 Mechanical Overhaul 220
30 Nine Mile Units 3 & 4 Control Upgrade 228
31 Noxon Rapids Generator Step-Up Bank C Replacement 234
32 Noxon Rapids Spillgate Refurbishment 240
33 Post Street Substation Crane Rehab 248
34 Regulating Hydro 258
35 Upper Falls Trash Rake Replacement 266
36 Energy Imbalance Marke 274
37 Energy Market Modernization & Operational Efficienc 286
38 Generation Plant Annunciation Systems 297
39 Automation Replacement 303
Exhibit No. 6, Schedule 4
Capital Investment Business Case Justification Narratives Index
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 1 of 309
Cabinet Gorge Dam Fishway

Business Case Justification Narrative Page 1 of 9
EXECUTIVE SUMMARY

The Clark Fork Settlement Agreement (CFSA) and FERC License require Avista to
implement the Native Salmonid Restoration Plan (NSRP), which includes a step­wise
approach to investigating, designing and implementing fish passage at the Clark Fork
Project. Appendix C of the CFSA commits Avista to fund Fishway design and construction
as well as annual operations. Fish passage is intended to restore connectivity of native
salmonid species in the lower Clark Fork watersheds. During relicensing the U.S. Fish &
Wildlife Service (USFWS) reserved its authority under Section 18 of the Federal Power
Act to require fish passage at both Noxon Rapids and Cabinet Gorge dams, in order to
pursue the NSRP more collaboratively. Those efforts, including involvement of Native
American tribes and state agencies, as well as other stakeholders, continued over 15 years
to the current project.
The Agreement and License support all electric customers in Washington and Idaho by
authorizing the continued operation of Noxon and Cabinet dams. In Amendment No. 1 to
the CFSA, Avista agreed to construct and operate a permanent upstream fishway facility,
consistent with the objective and purpose of the design approved by a Design Review Team
(DRT) on January 13, 2013, and modified to include a two-chamber trap and siphon water
supply approved by the DRT in July 2017. Any subsequent changes in design that may affect
the design criteria identified in the final Basis of the Design Report will require approval by
the USFWS. This agreement provides protection for Avista from being ordered to build
alternative facilities and also satisfies obligations under the Endangered Species Act as well
as Federal Power Act Section 18. Approval of this business case and the estimated total
project cost of $63.7 million will benefit our customers by maintaining compliance with the
CFSA and FERC License and subsequent agreements, which provide operational flexibility
at Avista’s Noxon and Cabinet Gorge Facilities.
The completion of this project is anticipated in Q2 of 2023 with the successful outcome of
operational testing and project closeout reporting.

VERSION HISTORY
Version Author Description Date Notes
Draft Michael Truex Initial draft of original business case 6/30/2020
1.0 Michael Truex Completed business case 7/28/2020 Reviewed by Nate Hall
1.1 Michael Truex 2021 Update 7/9/2021 Reviewed by Nate Hall
1.2 Michael Truex 2022 Update 8/19/2021 Reviewed by Nate Hall

DocuSign Envelope ID: FD9C820E-2233-495C-BDF3-9427CF8883FC
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 2 of 309
Cabinet Gorge Dam Fishway

Business Case Justification Narrative Page 2 of 9
GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
Design and Construction of the Cabinet Gorge Dam Fishway (CGDF) that fulfills
the upstream fish passage requirements identified in the Clark Fork Settlement
Agreement (CFSA) and FERC License No. 2058 issued for Cabinet Gorge HED
in 2001.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
The project is driven by the CFSA and FERC License issued for Cabinet Gorge
HED in 2001. The CFSA and FERC license were amended in 2017 to establish
final terms and conditions with regulatory agencies having jurisdiction as to
specifics of the project. The project will start operation in 2022 and operate at
least through the term of the FERC license (2045).
1.3 Identify why this work is needed now and what risks there are if not approved or is deferred
Avista, working closely with interested stakeholder groups, began implementation
of an Upstream Fish Passage Program for Bull Trout in 2001 as part of Appendix
C of the CFSA. A similar program for Westslope Cutthroat Trout was initiated in
2015, and the results of this study will help inform future fish passage
decisions. Bull Trout are listed as threatened under the Endangered Species Act
and Westslope Cutthroat Trout are a species of species concern in both Montana
and Idaho. A number of fish collection methods have been employed to capture
these fish prior to upstream transport. The use of these methods has resulted in
some level of fish capture success; however, there is evidence the majority of the
fish that are approaching Cabinet Gorge Dam are not being captured and not all
fish that are captured are captured the first time they approach the dam. The
Cabinet Gorge Dam Fishway (CGDF) is being constructed to capture a larger
Requested Spend Amount $63.7M
Requested Spend Time Period 2013 - 2023
Requesting Organization/Department B04 / Clark Fork License
Business Case Owner | Sponsor Nate Hall | Bruce Howard
Sponsor Organization/Department A04 / Environmental Affairs
Phase Execution
Category Project
Driver Mandatory & Compliance
DocuSign Envelope ID: FD9C820E-2233-495C-BDF3-9427CF8883FC
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 3 of 309
Cabinet Gorge Dam Fishway

Business Case Justification Narrative Page 3 of 9
number of the migratory native salmonids that are approaching Cabinet Gorge
Dam. The goal of construction and operation of the CGDF is to provide timely and
effective upstream passage for native trout species in support of broad native
salmonid recovery and connectivity in the lower Clark Fork watershed. The
signatories to the CFSA agree that the construction and operation of upstream and
downstream fishways, and the provisions in Amendment No. 1 to the CFSA is in
the public interest and that it satisfies various agency authorities applicable to the
Project. Critical among the authorities cited are Section 18 of the Federal Power
Act, the Endangered Species Act, the Clean Water Act, state fishway and transport
regulations, and USFWS’s 1999 Biological Opinion for licensing and operating
the Project for the term of the License.
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the need listed above.
Avista agreed to construct and operate the CGDF as part of Amendment No. 1 to
the CFSA, consistent with the objective and purpose of the “100% design”
approved by the Design Review Team on January 13, 2013, modified to include a
two-chamber trap and siphon water supply approved by the Design Review Team
in July 2017, that is compliant with National Marine Fisheries Service fish passage
standards. Any changes to that design will require the approval of USFWS if the
change would impact criteria identified in the final Basis of Design Report. The
Basic Monitoring Plan and transport protocols may be modified from time to time
by the MC; however, Amendment No. 1 to the CFSA makes clear that the transport
protocols must be approved by USFWS for Bull Trout, and must be consistent
with the detailed pathogen sampling and upstream transport protocols set forth in
Section 5 and Appendix 2 of Amendment No. 1 to the CFSA. Therefore, the
success for this project would be Avista’s construction of the CGDF, as specified
in Amendment No. 1 to the CFSA, and willingness to conduct upstream fish
passage through operation of the CGDF or through other methods fully satisfying
any obligation Avista may have to mitigate for the Cabinet Gorge Dam’s blockage
of upstream fish passage for the term of the License and any subsequent annual
licenses. Parties may request minor modifications to the facility, but agree not to
require Avista to replace the CGDF or install alternative fishway facilities or to
make structural or operational changes to Cabinet Gorge generating facilities or
its reservoir. In the event the CGDF does not capture native salmonids in a manner
that is safe, effective and timely, the parties agree that Avista will alternatively re-
commence electrofishing, operation of the Cabinet Gorge hatchery ladder, and/or
hook-and-line fishing below Cabinet Gorge Dam.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
The Clark Fork Settlement Agreement (CFSA) under FERC License No.
2058 issued for Cabinet Gorge HED in 2001, and Amendment No. 1 of the
Clark Fork Settlement Agreement both stipulate that Avista will construct a
fish passage facility for Bull Trout at Cabinet Gorge Dam. As such, there
DocuSign Envelope ID: FD9C820E-2233-495C-BDF3-9427CF8883FC
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Schedule 4, Page 4 of 309
Cabinet Gorge Dam Fishway

Business Case Justification Narrative Page 4 of 9
is no alternative to constructing the facility. Not doing so could jeopardize
the FERC license and thus the ability to generate power at Cabinet Gorge
Dam. The current design is the result of years of consultation, as well as
value engineering, with the intent to build an effective permanent facility at
the lowest cost.
ASSUMPTIONS & EXPECTED CONDITIONS
 No alternative exists for construction of a fish passage facility at Cabinet Gorge Dam
(see above). This plan us a result of our license requirements and subsequent
negotiations.
 If Avista does not build a fish passage facility at Cabinet Gorge Dam FERC could
issue orders, penalties or even rescind our operating license.
 If Avista does not build a fish passage facility at Cabinet Gorge Dam the USFWS
could take legal action under Section 18 to order Avista to build the facility, with
none of the assurances enacted by agreement in the CFSA Amendment.
 Operations of the CGDF will be performed by the Environmental Affairs
Department’s staff.
1.5.2 For asset replacement, include graphical or narrative representation of metrics associated with the current condition of the asset that is proposed for
replacement. (N/A)

No alternative exists for construction of a fish passage facility at Cabinet Gorge Dam
(see above). The values below are for the construction bids and do not include full
Parametric or Analogous estimates with Avista Labor, contracted Engineering,
Overhead Loadings, and AFUDC.
Option Capital Cost (Construction Contract)
Start Complete
MJ Kuney Original Bid (no bond, tax, or risk registry) $41.8M 03/2019 12/2021
Slayden Original Bid (no bond, tax, or risk registry) $22.8M 03/2019 12/2019
Slayden GMP (includes tax, bond, and risk registry) $24.9M 03/2019 12/2019
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Once engineering support during construction, construction management and
inspection, and construction contracts were executed, the budget estimate was
developed using Parametric and Analogous estimating methods scaled over the
time of the project with a cost loaded construction schedule. Then Avista
anticipated labor, respective labor loadings, capital overhead loadings, and
AFUDC were applied per the project accounting and capital cost structure. 2020
construction delays related to the FERC Left Thrust Block Stability concerns and
engineering analysis, as well as, repairs to the temporary cofferdam have
negatively impacted the construction schedule and project expenditure schedule.
As a result, $1.9M of planned spend in 2021 has slid into 2022 and an additional need
DocuSign Envelope ID: FD9C820E-2233-495C-BDF3-9427CF8883FC
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 5 of 309
Cabinet Gorge Dam Fishway

Business Case Justification Narrative Page 5 of 9
of $235K in 2023 for the construction schedule slide, as well as, the FERC project
closeout period post construction startup support. Due to minor difficulties in startup
and spill season impacts in 2022, the final project closeout will result in $235K in 2023.
This is ultimately resulting in a total cost of capital of $63.7M.
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
Operations and maintenance costs will not be covered as part of this project and
will be managed through the ongoing implementation of the CFSA and License.
Capital costs forecasted annual include engineering service during construction,
construction management, special inspection, construction, startup,
commissioning, and nine months of post commissioning troubleshooting and
engineering support.
The project is anticipating the following capital costs:
- 2013 – 2018: $19.56M
- 2019: $10.87M
- 2020: $12.93M
- 2021: $12.97M
- 2022: $7.05M
- 2023: $235K
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
There is currently no Avista communication network at the Fish Handling and
Holding Facility. Engineering and IT will explore options to get communications
to and from the CGDF and the Handling and Holding Facility. The final facility
will be managed and operated by the Environmental Affairs staff at the Clark
Fork Natural Resource Office. In coordination with other departments, the local
Cabinet Gorge Dam staff will assist in performing some startup activities,
maintenance, and trouble shooting. Work larger in magnitude will be performed
by GPSS craft shops, and or subcontracted to local contractors.
2.4 Discuss the alternatives that were considered and any tangible risks and mitigation strategies for each alternative.
Alternatives and upstream fish passage and facility location were evaluated and
discussed in the design development and partnership with the CFSA Management
Committee and respective agencies involved. The project design package was
originally bid in late 2015. Due to high bid prices and timing, the bids were
rejected in early 2016. The project team then met with the lowest cost bidder and
went through a value engineering process through July 2016. The final design was
then completed from January 2017 to June 2018. An early contract was executed
with Slayden Construction to complete the cofferdam design for FERC and
USACE submission, support in permitting and develop a Guaranteed Maximum
Price (GMP) contract based on the Stantec 100% design documents.
DocuSign Envelope ID: FD9C820E-2233-495C-BDF3-9427CF8883FC
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 6 of 309
Cabinet Gorge Dam Fishway

Business Case Justification Narrative Page 6 of 9
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer. spend, and transfers to plant by year.
2020 construction delay has shifted the substantial completion and in-service date
to late April to early May 2022, final construction completion August 2022, and
FERC project closeout October 2022. Final Avista project closeout reporting, as-
builts, and archiving is scheduled for July 2023.
2.6 Discuss how the proposed investment aligns with strategic vision, goals, objectives and mission statement of the organization.
The delivery of this project is highly important in the sustainability and operations
of our Clark Fork River facilities and operating them safely and responsibly. The
project will focus of the people responsible the delivering with a strong emphasis
on performance. This nature of the project demands a collaborative environment
with the wide array of key stakeholder groups. These efforts aligns with Avista
values of collaboration and environmental stewardship.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
The project budget and total cost will be regularly reviewed with the project
steering committee, as well as, receive approvals as described below for any
changes in scope and cost.

Prudency is also measured by remaining in compliance the FERC License and
Clark Fork Settlement Agreement, such that we can continue to operate the Clark
Fork project for the benefit of our customers and company.
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
- GPSS Engineering; Electrical, Controls, Mechanical, Civil, Dam Safety
- Distribution Engineering
- Hydro Operations
- Environmental, Permitting, and Licensing
- Master Scheduler
- Asset Management
- Project Accounting, Finance, and Rates
- Supply Chain and Legal
- Corporate Communications
- Construction Inspection and Project Management

2.8.2 Identify any related Business Cases
This project was part of the Clark Fork Settlement Agreement business case
until 2018 when it was separated into its own business case.
DocuSign Envelope ID: FD9C820E-2233-495C-BDF3-9427CF8883FC
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 7 of 309
Cabinet Gorge Dam Fishway

Business Case Justification Narrative Page 7 of 9

3.1 Steering Committee or Advisory Group Information
 Project Sponsor:
 Bruce Howard – Senior Director Environmental Affairs

 Steering Committee:
 Bruce Howard – Senior Director Environmental Affairs
 Andy Vickers/Alexis Alexander – Director GPSS
 Nate Hall – Manager Clark Fork License
 Jacob Reidt – Manager Project Delivery

 Project Manager:
 Michael Truex – Generation Project Delivery

 Key Project Stakeholders:
 Bob Weisbeck – Manager of Hydro Ops & Maintenance
 Chris Clemens – Manager Plant Operations Hydro – Cabinet Gorge
 Elizabeth Frederickson – Manager Safety, Training Operations & Labor
Specialist
 Greg Hesler – Senior Counsell II
 Carie Mourin – Supervisor Hydro Compliance
 Andrew Burgess – Chief Operator
 Heide Evans – Environmental Budget Specialist
 Shawna Kiesbuy – Senior Manager Network Engineering
 Steve Lentini – Sr Hydro Ops Engineer II, Power Supply
 Pat Maher – Sr Hydro Ops Engineer II, Power Supply
 Scott Kinney – Director Power Supply

 Project Team:
 Shana Bernall – Supervisor Biologist NE
 Lisa Vollertsen – Environmental Scientist I
 Guy Paul – Senior Engineer II (Avista Project Technical Lead & QCIP Mgr)
 Dennis France – Mechanical Engineer
 Christian Lobdell – Controls Engineer
 Matthew Moots (IT/ET) – Project Manager
 Lindsay Fracas – Associate Project Manager
 Amanda Hester – Project Engineer
 Michael Truex – Project Manager
 Clint Smith – Stantec PM, Engineer of Record
 James Larsen – CM/Inspector STRATA & All West
 Slayden Construction Inc - Contractor

DocuSign Envelope ID: FD9C820E-2233-495C-BDF3-9427CF8883FC
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 8 of 309
Cabinet Gorge Dam Fishway

Business Case Justification Narrative Page 8 of 9
3.2 Provide and discuss the governance processes and people that will
provide oversight
The project will be led by the core project team. Any changes to scope, schedule
and budget will be submitted for approval to the steering committee and with the
respective cost thresholds as defined in the table below.

3.3 How will decision-making, prioritization, and change requests be
documented and monitored
The project is utilizing the Project Change Log to track and manage all Project
Change Requests (PCR) associated with the delivery of the construction project.
The PCR describes the need for change, supplemental documentation, related
project artifacts, change order proposals, and any other pertinent information.
PCR’s are then signed for approval by the project approval thresholds, and then
processed against the project risk registry, and or contract amendment with the
contractor.

DocuSign Envelope ID: FD9C820E-2233-495C-BDF3-9427CF8883FC
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 9 of 309
Cabinet Gorge Dam Fishway

Business Case Justification Narrative Page 9 of 9

The undersigned acknowledge they have reviewed the Cabinet Gorge Dam
Fishway and agree with the approach it presents. Significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.

Signature: Date:
Print Name: Nate Hall
Title: Mgr Clark Fork License
Role: Business Case Owner

Signature: Date:
Print Name: Bruce Howard
Title: Sr Dir Environmental Affairs
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
DocuSign Envelope ID: FD9C820E-2233-495C-BDF3-9427CF8883FC
Sep-01-2022 | 4:13 PM PDT
Sep-01-2022 | 3:41 PM PDT
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 10 of 309
Clark Fork Settlement Agreement
Business Case Justification Narrative Template Version: 04.21.2022 Page 1 of 6
EXECUTIVE SUMMARY

The ongoing operation of the Clark Fork Project is conditioned by the Clark Fork Settlement
Agreement (CFSA) and FERC License No. 2058. The CFSA and License are the result of a
multi-year stakeholder engagement and negotiation process, which established the terms of
the 45-year license issued to Avista. Imbedded in the License is the requirement to continue
to consult agencies, tribes and other stakeholders. In addition, the CFSA and License
provide decision-making participation for the settlement signatories, resulting in ongoing
negotiations on implementing license terms. The CFSA and License also include a number
of funding commitments to help achieve long-term resource goals in the Clark Fork and
related watersheds. Some items are relatively predictable each year; many others are
dynamic, depending on potential projects, natural resource conditions and evolving resource
management goals. Most projects are implemented with collaborating agencies and Tribes,
often with multiple funding sources.

Avista is required to develop an annual implementation plan and report, addressing all
Protection, Mitigation and Enhancement (PM&E) measures of the License. Implementation
of these measures is intended to address ongoing compliance with Montana and Idaho Clean
Water Act requirements, the Endangered Species Act, and state, federal and tribal water
quality standards, among other statutory and regulatory requirements. License articles also
describe our operational requirements for items such as minimum flows, and reservoir
levels, as well as dam safety and public safety requirements, land use, and related matters.

If the PM&Es and License articles are not implemented and/or funded, Avista would be in
breach of an agreement and in violation of its License. There would be risk for
administrative orders and penalties, new license requirements, increased mitigation costs,
and potential loss of operational flexibility of the Cabinet Gorge and Noxon Rapids Hydro
Electric Facilities. Loss of operational flexibility, or of these generation assets, would create
substantial new costs, which would be detrimental of all our electric customers. Funding of
the Clark Fork License implementation is essential to remain in compliance with the FERC
License and CFSA, which provides Avista the operational flexibility to own and operate the
Clark Fork hydroelectric facilities. Therefore, if these costs were not capitalized, Avista
would continue to implement license articles and all costs would be an operating expense.

VERSION HISTORY
Version Author Description Date Notes
Draft Nate Hall Initial draft of original business case 6/30/2020
1.0 Nate Hall Completed business case 7/23/2020
2.0 Nate Hall Update template Version 04.21.2022 8/25/22
DocuSign Envelope ID: 366673F4-4B8A-4BCE-B3F2-1A9B86525293
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 11 of 309
Clark Fork Settlement Agreement
Business Case Justification Narrative Template Version: 04.21.2022 Page 2 of 6
GENERAL INFORMATION

1. BUSINESS PROBLEM
[This section must provide the overall business case information conveying the benefit to the customer, what
the project will do and current problem statement]
1.1 What is the current or potential problem that is being addressed?
Funding of the Clark Fork License Implementation is essential to remain in compliance
with the FERC License and CFSA for permission to continue to own and operate the hydro-electric facilities. This commitment was made in 2001 and is ongoing. At that
time, Avista determined that the Settlement was in the best interest of Avista, our
customers, our shareholders, and the communities we serve. These decisions were documented throughout the process at that time.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
These activities fall under the category of Mandatory and Compliance associated with the Clark Fork Settlement Agreement and FERC License. Benefit to our customers and
the company is the ability to provide clean, reliable and cost-effective power.
1.3 Identify why this work is needed now and what risks there are if not approved or is deferred
If the PM&Es and license articles are not implemented and/or funded, we would be in breach of an agreement and in violation of our FERC License. There would be high risk
for penalties and fines, new license requirements, higher mitigation costs, and loss of operational flexibility of the Cabinet Gorge and Noxon Rapids Hydro Electric Facilities.
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the need listed above.
We are required to develop, in consultation with the Management Committee, an annual implementation plan and report, addressing all PM&E measures of the License.
In addition, implementation of these measures is intended to address ongoing compliance with Montana and Idaho Clean Water Act requirements, the Endangered
Requested Spend Amount $3,522,698
Requested Spend Time Period 1 year
Requesting Organization/Department B04 / Clark Fork Settlement Agreement
Business Case Owner | Sponsor Nate Hall / Bruce Howard
Sponsor Organization/Department A04 / Environmental Affairs
Phase Execution
Category Mandatory
Driver Mandatory & Compliance
DocuSign Envelope ID: 366673F4-4B8A-4BCE-B3F2-1A9B86525293
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 12 of 309
Clark Fork Settlement Agreement
Business Case Justification Narrative Template Version: 04.21.2022 Page 3 of 6
Species Act (fish passage), and state, federal and tribal water quality standards as
applicable. License articles also describe our operational requirements for items such as minimum flows, and reservoir levels, as well as dam safety and public safety
requirements.
1.5 Supplemental Information
NA
1.5.1 Please reference and summarize any studies that support the problem
[List the location of any supplemental information; do not attach]
1.5.2 For asset replacement, include graphical or narrative representation of metrics associated with the current condition of the asset that is proposed for
replacement.
2. PROPOSAL AND RECOMMENDED SOLUTION
[Describe the proposed solution to the business problem identified above and why this is the best and/or least
cost alternative (e.g., cost benefit analysis, attach as supporting documentation)]

Option Capital Cost Start Complete
Capital Funding $3,522,698 01 2023 12 2023
Would continue to implement program as an O&M
expense
$0 01 2023 12 2023
2.1 Describe what metrics, data, analysis or information was considered when preparing this capital request.
Examples include:
- Samples of savings, benefits or risk avoidance estimates
- Description of how benefits to customers are being measured
- Comparison of cost ($) to benefit (value)
- Evidence of spend amount to anticipated return
Reference key points from external documentation, list any addendums, attachments etc.

Primary consideration occurred during the multi-year negotiations that led to the CFSA
and License. If the PM&Es and license articles are not implemented and/or funded, Avista would be in breach of an agreement and in violation of our License. There would
be high risk for penalties and fines, new license requirements, higher mitigation costs, and loss of operational flexibility of the Cabinet Gorge and Noxon Rapids Hydro
Electric Facilities. Loss of operational flexibility, or of these generation assets, would
create substantial new costs, which would be detrimental to all our electric customers and the company. Funding of the Clark Fork License Implementation is essential to
remain in compliance with the FERC license and CFSA, which provides Avista the operational flexibility to own and operate the hydro-electric facilities
DocuSign Envelope ID: 366673F4-4B8A-4BCE-B3F2-1A9B86525293
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 13 of 309
Clark Fork Settlement Agreement
Business Case Justification Narrative Template Version: 04.21.2022 Page 4 of 6
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
How will the outcome of this investment result in potential additional O&M costs, employee or staffing
reductions to O&M (offsets), etc.?
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy
Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]

As these projects are regulatory obligations, if the capital dollars are not available, they
will need to implemented utilizing O&M dollars. Result would be an increase in O&M costs at least equal to the decrease in capital funding available.
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
[For example, how will the outcome of this business case impact other parts of the business?]

2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
If the PM&Es and license articles are not implemented and/or funded, Avista would be
in breach of an agreement and in violation of our License. There would be high risk for penalties and fines, new license requirements, higher mitigation costs, and loss of
operational flexibility of the Cabinet Gorge and Noxon Rapids Hydro Electric Facilities
2.5 Include a timeline of when this work will be started and completed. Describe when the investments become used and useful to the customer.
[Describe if it is a program or project and details about how often in a year, it becomes used-and-useful.
(i.e. if transfer to plant occurs monthly, quarterly or upon project completion).]
This is an ongoing commitment running with the Clark Fork FERC License #2058 and
will continue until the License expires in 2046
2.6 Discuss how the proposed investment aligns with strategic vision, goals, objectives and mission statement of the organization.
[If this is a program or compilation of discrete projects, explain the importance of the body of work.]
Remaining in compliance allows for the continued operation of the Clark Fork HEDs for
the benefit of our customers and company. This supports our commitments to collaboration, environmental stewardship, and trustworthiness – all to help deliver
clean, renewable energy for our customers.
2.7 Include why the requested amount above is considered a prudent investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed and re-evaluated throughout the project
Prudency is measured by remaining in compliance the FERC License and Clark Fork Settlement Agreement, such that we can continue to operate Noxon and Cabinet dams
for the benefit of our customers and company.
DocuSign Envelope ID: 366673F4-4B8A-4BCE-B3F2-1A9B86525293
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 14 of 309
Clark Fork Settlement Agreement
Business Case Justification Narrative Template Version: 04.21.2022 Page 5 of 6
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
FERC and over 20 other parties, including the States of Idaho and Montana, various federal agencies, five Native American tribes, and numerous Non-
Governmental Organizations. In addition, we coordinate with numerous internal
stakeholders, in particular within GPSS and Power Supply.

2.8.2 Identify any related Business Cases
[Including any business cases that may have been replaced by this business case]
Cabinet Gorge Dam Fishway Project has its own business case and supports
meeting the overall regulatory requirements of the FERC License and CFSA.
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
[Please identify and describe the steering committee or advisory group for initial and ongoing vetting, as a
part of your departmental prioritization process.]
3.2 Provide and discuss the governance processes and people that will provide oversight
In addition to the responsible managers, The Clark Fork License Manager,
Sr. Director of Environmental Affairs, and
Sr VP Energy Resources & Env Comp Officer, many other internal and external stakeholders provide oversite. Externally, we submit annual work plans and reports to
FERC for its review and approval. Many decisions are subject, per the License, to oversite by the Clark Fork Management Committee, consisting of settlement parties.
And many elements receive oversite from internal staff in GPSS and Power Supply
3.3 How will decision-making, prioritization, and change requests be documented and monitored
Through normal business case update process; each year of License
implementation varies. Each year’s budget is established internally at Avista
months prior to the actual capital work plan. In addition, resource conditions, permitting and other issues impact work plan implementation each year. As a
result, regular “truing up” is required
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Clark Fork Settlement Agreement and
agree with the approach it presents. Significant changes to this will be coordinated with and
approved by the undersigned or their designated representatives.
DocuSign Envelope ID: 366673F4-4B8A-4BCE-B3F2-1A9B86525293
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 15 of 309
Clark Fork Settlement Agreement
Business Case Justification Narrative Template Version: 04.21.2022 Page 6 of 6

Signature: Date:
Print Name: Nate Hall
Title: Mgr Clark Fork License
Role: Business Case Owner

Signature: Date:
Print Name: Bruce Howard
Title: Sr Dir Environmental Affairs
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

DocuSign Envelope ID: 366673F4-4B8A-4BCE-B3F2-1A9B86525293
Sep-01-2022 | 1:43 PM PDT
Sep-01-2022 | 1:56 PM PDT
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 16 of 309
Right-of-Way Use Permits

Business Case Justification Narrative Template Version: 04.21.2022 Page 1 of 9
EXECUTIVE SUMMARY

Avista owns and maintains electric transmission, distribution, and natural gas facilities which cross
public lands managed by a variety of state, federal and local agencies, as well as entities who own
extensive tracts, such as railroads. Traditionally, we have secured long-term rights-of-way permits
for these facilities, but have been required to renew them through an annual billing process. The
cost of renewing these permits continues to increase each year, ranging from 3% to 10% annually,
depending on the agency/entity, thereby increasing annual O&M expenses to the company and our
customers. This business case proposal is to secure long-term agreements with lump-sum
payments to reduce overall expenses related to labor of tracking, researching, and processing these
annual permits. In some cases, we have been able to negotiate a lower annualized cost over the
term of the permit by paying a lump sum up front. In either case, we reduce costs to the company
and our customers. Making long-term lump sum payments allows us to capitalize these costs, as
the permit is a long-term asset.

A final determination was made by project accounting that all right of way permits may be
capitalized since they are in the retirement catalog. The permit must be for a term of at least one
year.

Without capital funding, we will continue to incur increasing annual permitting fees and related
internal costs as an O&M expense. These costs affect all customers, electric and gas, in the entire
Avista service territory.

VERSION HISTORY
Version Author Description Date Notes
Draft Rod Price Initial draft of original business case 6/30/2020
1.0 Rod Price Completed business case 7/28/2020
2.0 Dave Byus Include all Right of Way permits 9/23/2021
3.0 Dave Byus Update template Version 04.21.2022 8/26/2022
DocuSign Envelope ID: 52106F18-113E-41E5-8E8D-D427ED4BD8A4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 17 of 309
Right-of-Way Use Permits

Business Case Justification Narrative Template Version: 04.21.2022 Page 2 of 9

GENERAL INFORMATION

1. BUSINESS PROBLEM
[This section must provide the overall business case information conveying the benefit to the customer, what
the project will do and current problem statement]
1.1 What is the current or potential problem that is being addressed?
Avista owns and maintains electric transmission, distribution, and natural gas facilities
which cross public lands managed by a variety of state, federal and local agencies, as
well as entities who own extensive tracts, such as railroads. As these rights of way
permits renew, we’ve been paying annually increasing fees, leading to increased O&M
expenses associated with both the permit costs and the labor to process them.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
This business case is directly tied to Reliability, Mandatory & Compliance, Performance
& Capacity, and Failed Plant & Operations. In order to legally construct, maintain and
upgrade our facilities on agency owned lands, we must acquire and renew rights of way
permits. While we would continue doing this work without this business case, the main
benefits to the customer are being able to negotiate lower fixed permit costs through
lump sum payments, as well as securing long term permits which will allow us to
maintain reliability in our infrastructure. In addition, we will reduce our labor costs for
managing these permits. We also reduce the risk of annual permits not being renewed,
or being modified unilaterally.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
Right of way permitting on agency-owned lands is an ongoing and necessary scope of
work. We will continue doing this work without an approved capital business case.
This business case is based on our potential of saving the company and our customers
Requested Spend Amount $250,000
Requested Spend Time Period annually.
Requesting Organization/Department V08 / Real Estate
Business Case Owner | Sponsor Dave Byus / Bruce Howard
Sponsor Organization/Department A04 / Environmenal Affairs
Phase Execution
Category Productivity
Driver Performance & Capacity
DocuSign Envelope ID: 52106F18-113E-41E5-8E8D-D427ED4BD8A4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 18 of 309
Right-of-Way Use Permits

Business Case Justification Narrative Template Version: 04.21.2022 Page 3 of 9
money over the long term by capitalizing permit fees and negotiating lower costs
through long term, lump sum payments.
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the need listed above.
Annual tracking of all agency permits costs, and then completing a comparative analysis
against past years.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
[List the location of any supplemental information; do not attach]
1.5.2 For asset replacement, include graphical or narrative representation of metrics associated with the current condition of the asset that is proposed for replacement.
2. PROPOSAL AND RECOMMENDED SOLUTION
[Describe the proposed solution to the business problem identified above and why this is the best and/or least
cost alternative (e.g., cost benefit analysis, attach as supporting documentation)]
We propose that through this business case, we will work with agencies to negotiate lump
sum payments for our rights of way permits, thereby securing long-term, and lower fixed
costs associated with acquiring and renewing these permits.
Discussion with project accounting in April 2020, a decision was made that right of way
(permit) are included in the retirement unit catalog and therefore can be capitalized
regardless of dollar amount but must be for a minimum of at least one year (reference
Capital vs O&M determination below)
DocuSign Envelope ID: 52106F18-113E-41E5-8E8D-D427ED4BD8A4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 19 of 309
Right-of-Way Use Permits

Business Case Justification Narrative Template Version: 04.21.2022 Page 4 of 9

Option Capital Cost Start Complete
Capitalize & negotiate lump sum payments $50,000 01 2023 12 2023
Capitalize all Right of Way permits $200,000 01 2023 12 2023
Keep paying annually increasing permit fees
through O&M dollars
$0 01 2023 12 2023
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Examples include:
- Samples of savings, benefits or risk avoidance estimates
- Description of how benefits to customers are being measured
- Comparison of cost ($) to benefit (value)
- Evidence of spend amount to anticipated return
Reference key points from external documentation, list any addendums, attachments
etc.

Review of past eight years permit costs, we feel that $200k annually will be enough to
cover renewals on all right of way use permits.

DocuSign Envelope ID: 52106F18-113E-41E5-8E8D-D427ED4BD8A4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 20 of 309
Right-of-Way Use Permits

Business Case Justification Narrative Template Version: 04.21.2022 Page 5 of 9
EXPENDITURE_ORGANIZATION V08
Expenditure Type 905 &
605

2014 2015 2016 2017 2018 2019 2020 2021
ALBERT SURVEYING LLC
4,725

2,310

BNSF
10,433

BNSF RAILWAY COMPANY
22,115

23,661

12,009

35,433

13,706

18,072

17,349

17,113
BONNEVILLE POWER ADMIN
500

BUREAU OF LAND MANAGEMENT
1,189

1,275

BUREAU OF RECLAMATION
100

9,800

CENTRAL OREGON & PACIFIC RAILROAD
17,107

18,353

19,653

20,294

17,872

21,415

23,066

23,725
CHICAGO TITLE COMPANY OF
WASHINGTON

163

CORP CREDIT CARD
795

442

COUNTY OF LINCOLN
688

DEPARTMENT OF NATURAL RESOURCES
655

655

DEPARTMENT OF THE INTERIOR – BLM
93

364

DEPT OF TRANSPORTATION
6,386

108

648

10,699

1,419
DOI / BLM
23,384

8,735

14,430

25,838

76,176

35,258

1,550

41,508
EAST SIDE HIGHWAY DISTRICT
3,625

1,875

F&AO USACE WALLA WALLA
1,700

FINANCIAL MANAGEMENT DIVISION
659

958

958

954

IDAHO DEPT OF PARKS & RECREATION
11,401

9,127

14,693

12,281

12,814

13,350

15,157

15,336
IDAHO TRANSPORTATION DEPARTMENT
500

100

50

IRON HORSE DEVELOPMENT LLC
550

735
IRON HORSE REAL ESTATE & PROPERTY
MGMT

800

835

905

800

700

700

100

105
KETTLE FALLS INTERNATIONAL RAILWAY
LLC

667

LEWIS COUNTY ASSESSOR
110

LEWISTON TRIBUNE
185

MONTANA RAIL LINK INC
7,914

7,914

7,914

7,914

7,914

8,214

2,320

8,014
NATIONAL PARK SERVICE
45

RAILROAD MANAGEMENT COMPANY II LLC
1,490
RAILROAD MANAGEMENT COMPANY III
LLC

21,532
DocuSign Envelope ID: 52106F18-113E-41E5-8E8D-D427ED4BD8A4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 21 of 309
Right-of-Way Use Permits

Business Case Justification Narrative Template Version: 04.21.2022 Page 6 of 9
RAILROAD MANAGEMENT COMPANY LLC
36,152

41,636

45,536

47,392

43,655

53,090

38,803

27,808
REAL ESTATE WORKING FUND
500

590

2,696

300

550
SPOKANE COUNTY
5,000

SPOKANE COUNTY ENGINEERS
5,000

5,564

5,500

5,500

SPOKANE COUNTY TREASURER
5,500

500

5,500

3,109
ST MARIES RIVER RAILROAD COMPANY
701
-
STATE OF MONTANA
13,925

TOPCON SOLUTIONS INC
359
TRIBUNE PUBLISHING COMPANY INC
98

UNION PACIFIC RAILROAD COMPANY
317

323

323

325

330

346

349
UNITED STATES BUREAU OF RECLAMATION
15,075

US ARMY CORP OF ENGINEERS
4,600
US DEPARTMENT OF THE INTERIOR
22,192

16,771

440

3,388

USDA FOREST SERVICE
8,925

3,812

7,136

6,489

3,639

6,764

(12,587)

11,422
WASHINGTON DEPT OF NATURAL
RESOURCES

20,000

WASHINGTON STATE DEPT OF
TRANSPORTATION

432

3,614

FOREST SERVICE US PERMIT TRUE UP - -
4,882

(4,908)

62,054

Grand Total
182,683

138,837

166,021

159,282

197,603

170,715

192,289

179,175

After the first year of this business case, we are seeing an increase in the costs and need to increase the business case to accommodate rising expenses to $250k.
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
How will the outcome of this investment result in potential additional O&M costs, employee or staffing
reductions to O&M (offsets), etc.?
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy
Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]
DocuSign Envelope ID: 52106F18-113E-41E5-8E8D-D427ED4BD8A4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 22 of 309
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Starting in 2021, the capital cost amount will be used primarily to cover the costs of
agency right of way fees. There should be minimal labor costs associated with this
activity, and the annual labor costs should reduce slightly if the number of annual
renewals is reduced through the negotiation of long-term permits.
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
[For example, how will the outcome of this business case impact other parts of the business?]
By taking annually renewing permits, and converting them to longer-term permits, we
should positively impact the labor associated with processing annual permits.
2.4 Discuss the alternatives that were considered and any tangible risks and mitigation strategies for each alternative.
The only other alternative is to continue processing annual permits and paying the
annually increasing fees, which is a charge to company O&M.
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
[Describe if it is a program or project and details about how often in a year, it becomes used-and-useful.
(i.e. if transfer to plant occurs monthly, quarterly or upon project completion).]
This is a program and the work is completed throughout the year based on when agency
permits are received. They will become used and useful once the fully executed permit
is in place.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
[If this is a program or compilation of discrete projects, explain the importance of the body of work.]
Our proposed investment is aligned with Avista’s mission of delivering reliable power
to our customers at the most affordable price we can deliver. Rights of way permits
are required for Avista to construct, maintain, and upgrade electric and gas
infrastructure on agency owned land. Without these rights of way, we cannot meet our
objectives
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
Without this business case, we will still be required to do the same work, thereby
continuing to pay increasing O&M costs. This program proposal is prudent, as it will
help mitigate long-term expenses for the company and our customers
2.8 Supplemental Information

DocuSign Envelope ID: 52106F18-113E-41E5-8E8D-D427ED4BD8A4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 23 of 309
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2.8.1 Identify customers and stakeholders that interface with the business case
Electric and Gas operations are impacted by this business case as we are securing
rights of way for these facilities. Avista’s electric and gas customers are also
affected by our ability to provide reliable and low-cost power.
2.8.2 Identify any related Business Cases
[Including any business cases that may have been replaced by this business case]

3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
[Please identify and describe the steering committee or advisory group for initial and ongoing vetting, as a
part of your departmental prioritization process.]
This program will be monitored by the Real Estate Manager, Sr. Director of
Environmental Affairs, and Department Financial & Budget Specialist.
3.2 Provide and discuss the governance processes and people that will provide oversight
This program will be monitored by the Real Estate Manager, Sr. Director of
Environmental Affairs, and Department Financial & Budget Specialist. We will
evaluate the annual costs and savings to ensure the program is on track.
3.3 How will decision-making, prioritization, and change requests be documented and monitored
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Right-of-Way Use Permits and agree
with the approach it presents. Significant changes to this will be coordinated with and
approved by the undersigned or their designated representatives.

Signature: Date:
Print Name: Dave Byus
Title: Mgr Real Estate
Role: Business Case Owner

Signature: Date:
Print Name: Bruce Howard
Title: SR Dir Environmental Affairs
DocuSign Envelope ID: 52106F18-113E-41E5-8E8D-D427ED4BD8A4
Sep-02-2022 | 8:19 AM PDT
Sep-02-2022 | 8:48 AM PDT
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 24 of 309
Right-of-Way Use Permits

Business Case Justification Narrative Template Version: 04.21.2022 Page 9 of 9
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

DocuSign Envelope ID: 52106F18-113E-41E5-8E8D-D427ED4BD8A4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 25 of 309
Spokane River License Implementation

Business Case Justification Narrative Page 1 of 7
EXECUTIVE SUMMARY

Non-federal hydroelectric facilities must have a license from the Federal Energy Regulatory Commission
(FERC) to operate. Avista’s first Spokane River Project License expired in 2007, and after a multi-year process
involving hundreds of stakeholders, FERC issued Avista a new 50-year license for the continued operation and
maintenance of the Spokane River Project (No. 2545, effective June 18, 2009). This license covers the Post
Falls, Upper Falls, Monroe Street, Nine Mile and Long Lake Hydroelectric Developments. This license defines
how Avista shall operate the Spokane River Project and includes several hundred requirements, through
license conditions, that we must meet. The license was issued pursuant to the Federal Power Act (FPA) and
embodies the requirements of a wide range of other laws (The Clean Water Act, The Endangered Species Act,
The National Historic Preservation Act, etc.). These requirements are expressed through specific license
articles relating to fish, terrestrial, water quality, recreation, land use, education, cultural and aesthetic
resources. Avista also entered into additional two-party agreements with local, state, and federal agencies
and the Coeur d’Alene and Spokane Tribes. Avista’s FERC license and agreements include mandatory
conditions issued by the Idaho Department of Environmental Quality (401 Water Quality Certification, issued
June 5, 2008), the Washington Department of Ecology (401 Water Quality Certification, issued May 8, 2009),
the U.S. Forest Service (Federal Power Act 4(e), issued May 4, 2007), and the U.S. Department of Interior on
behalf of the Coeur d’Alene Tribe (Federal Power Act 4(e), filed January 27, 2009). The FERC license ensures
Avista’s ability to operate the Spokane River project on behalf of our electric customers within our service
territory for a 50-year license term with an annual cost that varies annually.

Complying with our license is mandatory to continued permission to operate the Spokane River Project and
funding the implementation activities is essential to remain in compliance with the FERC license. Specific
elements of this program change from year to year, depending on license requirements as well as resource
conditions. Ongoing stakeholder engagement, and therefore, negotiation, is also required by the license. As
a result, some elements of the license are relatively predictable and static while others are dynamic and
evolving.

Now that the license has been issued for a term of 50-years, governance is multi-faceted and includes the
Spokane River License team engaging with regulatory agencies, external and internal stakeholders in annual,
five-year, and ten-year planning to implement the license and settlement agreement conditions.
Implementation measures for each of the natural resource conditions have specific success criteria identified.
This data along with key accomplishments are reported/documented as part of the license conditions, along
with agency/stakeholder approvals. Internal governance can include steering committees for specific major
projects, as well as the organizational hierarchy within which the Spokane River team operates. Work
coordination occurs through multi-departmental meetings and work planning.

If this business case is not approved, Avista will continue compliance with the FERC license and all costs
would be Operating expenses.

VERSION HISTORY
Version Author Description Date Notes
Draft Meghan Lunney Initial draft of original business case 7/7/2020
1.0 Meghan Lunney Complete business case 7/28/2020
2.0 Meghan Lunney Update template Version 04.21.2022 9/1/2022
DocuSign Envelope ID: B4E347E9-3FBA-4E65-9911-C2813D7AFAE4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 26 of 309
Spokane River License Implementation

Business Case Justification Narrative Page 2 of 7
GENERAL INFORMATION

1. BUSINESS PROBLEM

1.1 What is the current or potential problem that is being addressed?
Non-federal hydroelectric facilities must have a license from the Federal Energy Regulatory
Commission (FERC) to operate. Avista’s first Spokane River Project License expired in 2007, and
after a multi-year process involving hundreds of stakeholders, FERC issued Avista a new 50-year
license for the continued operation and maintenance of the Spokane River Project (No. 2545,
effective June 18, 2009). This license covers the Post Falls, Upper Falls, Monroe Street, Nine Mile
and Long Lake Hydroelectric Developments. This license, based in large part on settlement
agreements, defines how Avista shall operate the Spokane River Project and includes several
hundred requirements, expressed as license conditions, that we must meet. The license was
issued pursuant to the Federal Power Act (FPA) and embodies the requirements of a wide range
of other laws (The Clean Water Act, The Endangered Species Act, The National Historic
Preservation Act, etc.). These requirements are expressed through specific license articles relating
to fish, terrestrial, water quality, recreation, land use, education, cultural and aesthetic resources.
Avista also entered into additional two-party agreements with local, state, and federal agencies
and the Coeur d’Alene and Spokane Tribes, most of which are embodied in the License. Avista’s
FERC license and agreements include mandatory conditions issued by the Idaho Department of
Environmental Quality (401 Water Quality Certification, issued June 5, 2008), the Washington
Department of Ecology (401 Water Quality Certification, issued May 8, 2009), the U.S. Forest
Service (Federal Power Act 4(e), issued May 4, 2007), and the U.S. Department of Interior on
behalf of the Coeur d’Alene Tribe (Federal Power Act 4(e), filed January 27, 2009). The FERC
license ensures Avista’s ability to operate the Spokane River project on behalf of our electric
customers within our service territory for a 50-year license term. The capital costs of
implementing the License varies each year, depending on specific requirements and opportunities
to accomplish projects.

Requested Spend Amount $825,800
Requested Spend Time Period 1 year
Requesting Organization/Department CO4 / Spokane River License Implementation
Business Case Owner | Sponsor Meghan Lunney | Bruce Howard
Sponsor Organization/Department A04 / Environmental Affairs
Phase Execution
Category Mandatory
Driver Mandatory & Compliance
DocuSign Envelope ID: B4E347E9-3FBA-4E65-9911-C2813D7AFAE4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 27 of 309
Spokane River License Implementation

Business Case Justification Narrative Page 3 of 7
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
Complying with our license is mandatory for continued permission to operate the Spokane River
Project. Funding implementation activities is essential to remain in compliance with the FERC
license. Specific elements of this program change from year to year, depending on license
requirements as well as resource conditions. Ongoing stakeholder engagement, and therefore,
negotiation, is also required by the license. As a result, some elements of the license are
relatively predictable and static while others are dynamic and evolving.

1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
Complying with our license is mandatory to continued permission to operate the Spokane River
Project and funding the implementation activities is essential to remain in compliance with the
FERC license. Ultimately, FERC has the authority to issue orders and penalties, or in the extreme,
revoke our license, if we do not comply with the terms and conditions required by it. Loss of
operational flexibility, or in the extreme, loss of our generation assets, would create substantial
new costs to our customers and no benefits. In addition, Avista would suffer reputational costs
for not meeting our commitments.

1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the need listed above.
The Spokane River License team engages with the regulatory agencies and stakeholders in annual,
five-year, and ten-year planning to implement the license and settlement agreement conditions.
Implementation measures for each of the natural resource conditions have specific success
criteria identified. This data along with key accomplishments are reported/documented as part of
the license conditions, along with agency/stakeholder approvals. We, as well as FERC, maintain a
complete record of our stakeholder consultation, work and project planning, and reported
results.

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
Federal Energy Regulatory Commission (FERC). 2009. Order Issuing New License and
Approving Annual Charges For Use Of Reservation Lands. Issued June 18.
Avista. 2005. Spokane River Hydroelectric Project, FERC No. 2545, Final Application for
New License Major Project – Existing Dam. July 2005.
Avista. 2005. Post Falls Hydroelectric Project, Currently Part of Project No. 2545, Final
Application for New License Major Project – Existing Dam. July 2005.

DocuSign Envelope ID: B4E347E9-3FBA-4E65-9911-C2813D7AFAE4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 28 of 309
Spokane River License Implementation

Business Case Justification Narrative Page 4 of 7
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for replacement.
NA.

Complying with our license is mandatory to continued permission to operate the Spokane River
Project. Funding the implementation activities for the Spokane River Project License is essential to
remain in compliance with the FERC license. There are no practicable alternatives to meet compliance.
Avista evaluated the potential of surrendering the Spokane River license at the beginning of the
relicensing process, determining that this option would be detrimental to our customers, the company
and the communities we serve.
If the PM&Es, license articles and settlement agreements are not implemented and/or funded, we
would be out of compliance and/or in violation of our License. This would lead to penalties and fines,
new license requirements, court costs, higher mitigation costs, and loss of operational flexibility.
Ultimately, FERC has the authority to revoke our License if we do not comply with the terms and
conditions required by it. Loss of operational flexibility, or in the extreme, loss of our generation
assets, would create substantial new costs to our customers and no benefits.
Option Capital Cost Start Complete
Capital Funding $825,800 01 2023 12 2023
Activity is mandatory and will result in an operational
cost overage
$0 01 2023 12 2023
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.

Implementation measures conducted under this capital request are based upon regular meetings
engaging with regulatory agencies and external and internal stakeholders during annual, five-
year, and ten-year planning meetings. Implementation measures for each of the natural resource
conditions have specific success criteria identified. This data along with key accomplishments are
reported/documented as part of the license conditions, along with agency/stakeholder approvals.
At every opportunity during project planning cost sharing options and opportunities are fully
explored to ensure Avista’s fiduciary duty to its customers is upheld.

2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
The requested capital costs will be implemented in accordance with the schedules, milestones
and benchmarks identified in the annual planning process as identified and committed to within
annual, five-year and ten-year workplans. The work is completed in collaboration with internal
and external stakeholders.

2.3 Outline any business functions and processes that may be impacted (and how) by the business case for it to be successfully implemented.
The Spokane River implementation activities are coordinated across many internal departments
to ensure other business functions/processes are not impacted. Collaboration is an essential
DocuSign Envelope ID: B4E347E9-3FBA-4E65-9911-C2813D7AFAE4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 29 of 309
Spokane River License Implementation

Business Case Justification Narrative Page 5 of 7
component of the work and successful implementation is dependent upon input from other
internal departments. GPSS and Power Supply, in particular, depend on the successful
implementation of our License activities.
2.4 Discuss the alternatives that were considered and any tangible risks and mitigation strategies for each alternative.
There are no practicable alternatives to meeting compliance. Avista evaluated the potential of
surrendering the Spokane River license at the beginning of the relicensing process, determining
that this option would be detrimental to our customers, the company and the communities we
serve.

2.5 Include a timeline of when this work will be started and completed. Describe when the investments become used and useful to the customer.
spend, and transfers to plant by year.
Implementing the license activities will take place over the course of the year extending from
January through December. Transfers will happen throughout the course of the year.

2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Implementing the required Spokane River license conditions during 2020 is required by the FERC
license in order to operate the Spokane River Hydroelectric Project. This ensures a reliable
energy supply for our customers. The License is the result of seven years of community-based
collaboration, and implementation also reflects ongoing collaboration with key stakeholders.
Additionally, these implementation measures showcase Avista’s ongoing commitment to
environmental stewardship which benefits our customers, the company and the communities we
serve.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
The requested capital costs will be implemented in accordance with the schedules, milestones
and benchmarks identified in the annual planning process as identified and committed to within
annual, five-year and ten-year workplans. The work is completed in collaboration with internal
and external stakeholders. At every opportunity during project planning cost sharing options and
opportunities are fully explored to ensure Avista’s fiduciary duty to its customers is upheld.
Project costs are reviewed monthly, if not weekly, and managed tightly by each Spokane River
resource lead, budget analyst and the Spokane River License Manager.
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
The majority of our external agency stakeholders that interface with this business case include
the Idaho Department of Environmental Quality, Idaho Department of Fish and Game, Idaho State
Historic Preservation Office, Idaho Department of Lands, Washington Department of Ecology,
Washington Department of Fish and Wildlife, Washington State Historic Preservation Office,
Washington Department of Natural Resources, U.S. Forest Service, U.S. Fish and Wildlife Service,
DocuSign Envelope ID: B4E347E9-3FBA-4E65-9911-C2813D7AFAE4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 30 of 309
Spokane River License Implementation

Business Case Justification Narrative Page 6 of 7
U.S. Department of Interior, Coeur d’Alene Tribe, and Spokane Tribe. Additional external
stakeholders including conservation districts, non-profits, and local educational institutions, as
well as a number on non-governmental environmental organizations.

Major internal stakeholders include GPSS, Power Supply, External Communications, etc.

2.8.2 Identify any related Business Cases
NA.

3.1 Steering Committee or Advisory Group Information
Prior to receiving the license, during the seven-year relicensing process, we engaged stakeholders
in direct negotiations and we also engaged in litigation to challenge some proposed conditions.
Avista's officers and Board were updated regularly during these efforts, and officers were
engaged at key decision points. Now that the license has been issued for a term of 50-years,
governance is multi-faceted and includes the Spokane River License team engaging with
regulatory agencies, stakeholders, and many internal departments including GPSS, Power Supply,
and External Communications to ensure the appropriate governance is applied per natural
resource implementation condition.
3.2 Provide and discuss the governance processes and people that will
provide oversight
Now that the license has been issued for a term of 50-years, governance is multi-faceted and
includes the Spokane River License team engaging with regulatory agencies, external and internal
stakeholders in annual, five-year, and ten-year planning to implement the license and settlement
agreement conditions. Implementation measures for each of the natural resource conditions
have specific success criteria identified. This data along with key accomplishments are
reported/documented as part of the license conditions, along with agency/stakeholder approvals.
Internal governance can include steering committees for specific major projects, as well as the
organizational hierarchy within which the Spokane River team operates. Work coordination
occurs through multi-departmental meetings and work planning.

3.3 How will decision-making, prioritization, and change requests be
documented and monitored
Decision-making, prioritization, and change requests will be documented and monitored by each
natural resource lead on the Spokane River Team and reviewed by the Spokane River License
Manager and others, depending on financial authority. Budget is tracked and reviewed on a
monthly, if not weekly basis, and a change request form will be completed should additional, or
less, funding be needed to implement the license conditions under this business case. Spending
and invoices are reviewed and tracked at each level within the organization per budget approval
authorities.
The undersigned acknowledge they have reviewed the Spokane River License
Implementation and agree with the approach it presents. Significant changes to this will be coordinated with and approved by the undersigned or their designated
representatives.
DocuSign Envelope ID: B4E347E9-3FBA-4E65-9911-C2813D7AFAE4
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 31 of 309
Spokane River License Implementation

Business Case Justification Narrative Page 7 of 7

Signature: Date:
Print Name: Meghan Lunney
Title: Mgr Spokane River License
Role: Business Case Owner

Signature: Date:
Print Name: Bruce Howard
Title: Sr Dir Environmental Affairs
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
DocuSign Envelope ID: B4E347E9-3FBA-4E65-9911-C2813D7AFAE4
Sep-01-2022 | 4:14 PM PDT
Sep-01-2022 | 3:54 PM PDT
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 32 of 309
Base Load Thermal Program 2023 - 2027
Business Case Justification Narrative Page 1 of 9
EXECUTIVE SUMMARY

This business case request is for Avista’s base load thermal plants: Kettle Falls
and Coyote Springs 2. This program enables these plants to have operational
flexibility and are operated to support energy supply, peaking power, provide continuous and automatic adjustment of output to match the changing system loads,
and other types of services necessary to provide a stable electric grid and to
maximize value to Avista and its customers. Smaller and emergent projects planned
for Kettle Falls are identified and prioritized through their plant Budget Committee.
The plant Budget Committee utilizes an in-house Maintenance Project Review scoring matrix.
Projects planned specifically for Coyote Springs 2 are identified and prioritized
during the Annual Budgeting process, with emergent projects discussed during the
Monthly Owners committee meetings between Avista management and Coyote
Springs management. Some of the projects that fall within this business case are joint projects between Portland General Electric (PGE) and Avista. Those
“common” projects are also reviewed in an owner committee setting during meetings
at the plant that take place on a monthly basis.
The operational availability for these plants is paramount. The service code for this
program is Electric Direct and the jurisdiction for the program is Allocated North serving our electric customers in Washington and Idaho
Individual projects are identified and approved by the Manager of Thermal
Operations and Maintenance, specific plant managers and/or GPSS management.
Some specific jobs under this program may require additional financial analysis if
they are sufficiently large or there are several options that can be chosen to meet the objective. These projects are reviewed with finance personnel to make sure that
they are in the best interest of our customers.

VERSION HISTORY
Version Author Description Date Notes
Draft Greg Wiggins Initial draft of original business case 7/8/2020
Mike Mecham Updated 7/6/2021 For years 2022 - 2026
Mike Mecham Updated 8/19/2022 For years 2023 - 2026

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 33 of 309
Base Load Thermal Program 2023 - 2027
Business Case Justification Narrative Page 2 of 9
GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
Due to the age and continuous use of the base load thermal facilities, more and
more critical assets, support systems, and equipment are reaching the end of
their useful life. In addition, it is difficult to predict failures and unscheduled problems of operating thermal generating facilities. This program is critical in providing funding to support the replacement of critical assets and systems that
support the reliable operations of these critical facilities.
1.2 Discuss the major drivers of the business case
The major drivers for this business case are Asset Condition and Failed Plant. This program provides funding for small capital projects that are required to support the safe and realiable operation of these thermal facilities. The flexible
operations and generating capacity of these plants maximize value for Avista and
our customers.
1.3 Identify why this work is needed now and what risks there are if not approved or is deferred.
Critical asset condition and failed equipment jeopardize the safe and reliable
operation of these generating facilities. If problems are not resolved in a timely
manner, the plant and plant personnel could be at risk and failed or unavailable
critical assets and systems will limit plant flexibility and availability. This could
have a substantial cost impact to Avista and our customers.
Without this funding source it will be difficult to resolve relatively small projects
concerning failed equipment and asset condition in a timely manner. This will
jeapordize plant availability and greatly impact the value to customers and the
stability of the grid.

Requested Spend Amount $13,950,000
Requested Spend Time Period 2023 - 2027
Requesting Organization/Department C06, K07 / GPSS
Business Case Owner | Sponsor Thomas Dempsey | Alexis Alexander
Sponsor Organization/Department C06, K07 / GPSS
Phase Initiation
Category Program
Driver Asset Condition / Failed Equipment
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 34 of 309
Base Load Thermal Program 2023 - 2027
Business Case Justification Narrative Page 3 of 9
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
Plant reliability and availability is measured, as well as the frequency and nature of forced outages. These metrics will contribute to prioritizing the projects in this
program. Historically, this program has funded multiple projects per year which
contributed to unit availability.

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem

The historical drivers of the projects selected to be funded by the program are a mix of Asset Condition and Failed Plant. Projects are typically completed in
the calendar year.

1.5.2 For asset replacement, include graphical or narrative representation of metrics associated with the current condition of the asset that is proposed for replacement.

Being a Program, this review will be performed on a project by project basis.
This decision will be made by the program Steering Committee.

Using funds from the Base Load Thermal Program, spend $2,790,000 per year in
2022-2026; to “keep the lights on”.

Option Capital Cost Start Complete
Base Load Thermal Program 13,950,000 01/2023 12/2027
Individual Capital Projects 13,950,000 01/2023 12/2027

Describe what metrics, data, analysis or information was considered when preparing this capital request.
2.1
Review of the recent program budget has revealed the a realistic annual budget
is $3,100,000. In order to support the capital budget goals of the GPSS department, this budget has been reduced by 10% to $2,790,000 for years 2023 through 2027. Projects with lower risk will be delayed through this period.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 35 of 309
Base Load Thermal Program 2023 - 2027
Business Case Justification Narrative Page 4 of 9
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include any known or estimated reductions to O&M as a result of this investment.

If capital funds were not available for the projects in this program, reliability of
the plant would decrease and more O&M would need to be performed to repair aging equipment instead of replacement. This would be an unacceptable and substantial increase in the O&M expenditures.
The projects in this program typically take place during the outages which are in
the late spring and fall of each year. Most of the capital is deployed in the 2rd
and 4th quarter of each year.
If capital funds were not available for the projects in this program, reliability of the plant would decrease and more O&M would need to be performed to repair
aging equipment instead of replacement. Due to the nature of the Capital
projects covered under the Base Load Generation Program, forced outages and
reliability are difficult to quantify. Should forced outages occur due to the inability to cover Capital projects under this program, daily estimated Power Supply outage costs associated with the Base Load Thermal facilities covered under
this Program are estimated to be:
Coyote Springs 2: $206,800
Kettle Falls Wood: $69,700
Kettle Falls CT: $400
(refer to 20220825 Thermal Daily Outage Cost Estimation Tool
CONFIDENTIAL.xlsx)

2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 36 of 309
Base Load Thermal Program 2023 - 2027
Business Case Justification Narrative Page 5 of 9
These projects vary in size and support needed from the Department and key
stakeholders. The larger projects require formal project management with a
broader stakeholder team. Medium to small projects can be implemented by a project engineer or project coordinator and many cases can be handled by contractors mananaged by the regional personnel. All of these projects are
prioritized and coordinated by the broader support team.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
One alternative would be to create business cases using the business case template and process for each of these small projects. There are typically 40-
50 projects a year funded by the program. This would overload the Capital
Budget Process with small to medium projects whose governance can be
effectively handled by the Thermal Organization. These projects are specific to these plants and the leadership in Thermal Operations understand the best the nature and context of these projects.
These projects are somewhat unpredictable. It would be difficult to forecast
unforeseen events such as equipment failures and identify critical asset
condition that could effectively be put in the annual capital plan.
Another alternative would be to attempt to repair this equipment instead of replacing critical assets at the end of their lifecycle. This will be unacceptably
expensive and older equipment will become more and more unreliable until it
becomes obsolete. Operating in a run-to-failure mode is proven to be an
unsuccessful approach and subjects Avista and its customers to unacceptable risk.

2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.

The projects in this program for Kettle Falls and Coyote Springs 2 typically take place during the annual outages, which are typically in May-June of each year.

2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.

The purpose of this program is to provide funding to small to medium size
projects with the objective of keeping our thermal plants reliable and available
to support the power needs of our company and our customers affordably. By
doing this we support our mission of improving our customer’s lives through
innovative energy solutions which includes thermal generation. By executing the projects funded by the program, we insure that Thermal Facilities are performing
at a high level and serving our customers with affordable and reliable energy.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 37 of 309
Base Load Thermal Program 2023 - 2027
Business Case Justification Narrative Page 6 of 9

2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In addition, please explain how the investment prudency will be reviewed and re-evaluated throughout the project
Review of the recent program budget has revealed the a realistic annual budget
is $3,100,000. In order to support the capital budget goals of the GPSS
department, this budget has been reduced by 10% to $2,790,000 for years 2022 through 2026. Projects with lower risk will be delayed through this period.
The drivers of the projects selected to be funded by this program are mix Asset
Condition and Failed Plant. Resolving issues encountered in operating these plants in
a timely manner benefits the customers with providing safe, reliable, low cost power which supports the needs of Bulk Electric System and provides value to Avista and our
customers.

2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business
case

The list of primary customers and stakeholders includes: GPSS, Environmental
Resources, Power Supply, Systems Operations, ET, and electric customers in
Washington and Idaho

2.8.2 Identify any related Business Cases

None.

3.1 Steering Committee or Advisory Group Information
The Kettle Falls plant uses a Budget Committee to evaluate, prioritize, and oversee project work at the station. This group consists of the Plant Manager, Asst Plant
Manager, Plant Mechanic and a Plant Technician.
The plant Budget Committee utilizes GPSS Department Project Ranking Matrix.
The review process focuses around Personnel and Public Safety, Environmental
Concerns, Regulatory/Insurance Mandates, Ongoing Maintenance Issues, Decreasing Future Operating Costs, Increasing Efficiency, Managing Obsolete
Equipment and Assessing the Risk of Equipment Failure.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 38 of 309
Base Load Thermal Program 2023 - 2027
Business Case Justification Narrative Page 7 of 9
For Coyote Springs 2, monthly owners committee meetings between Avista
management and Coyote Springs management discuss and prioritize projects.
Some of the projects that fall within this business case are joint projects between
Portland General Electric (PGE) and Avista. Those “common” projects are also reviewed in an owner committee setting during meetings at the plant that take place
on a monthly basis.

3.2 Provide and discuss the governance processes and people that will provide oversight
Projects are proposed through various organizations in Generation Production and
Substation Support (GPSS) and through key stakeholder such as Environmental
Resources, and Safety and Security. The projects are vetted by the Advisory Group.
With the assistance of Operations, Construction and Maintenance and Engineering, projects are evaluated to determine available options, confirm prudency, and bring potential solutions forward.
This same vetting process is followed for emergency projects and may included
other key stakeholders. Over the course of the year, the program is actively
managed by the Plant Managers, with the assistance of their Advisory Groups. This includes monthly analysis of cost and project progress and reporting of expected spend.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 39 of 309
Base Load Thermal Program 2023 - 2027
Business Case Justification Narrative Page 8 of 9
3.3 Provide and discuss the governance processes and people that will
provide oversight
Projects are proposed through various organizations in Generation Production and Substation Support (GPSS) and through key stakeholder such as Environmental Resources, and Safety and Security. The projects are vetted by
the Advisory Group. With the assistance of Operations, Construction and
Maintenance and Engineering, projects are evaluated to determine available
options, confirm prudency, and bring potential solutions forward.
This same vetting process is followed for emergency projects and may included other key stakeholders. Over the course of the year, the program is actively
managed by the Plant Managers, with the assistance of their Advisory Groups.
This includes monthly analysis of cost and project progress and reporting of
expected spend.
3.4 How will decision-making, prioritization, and change requests be documented and monitored
Each project request will be evaluated by the Advisory Group which will include
the scope, cost and risk associated with the project. The project will be
evaluated based on the impact or potential impact of the operation of the Thermal plants. The selection and approval of the project will be based on the experience and consensus of the Advisory Group.
Depending on the size of the project, a Project Manager or Project Coordinator
may be assigned. They will follow the project management process for reporting
and identifying and executing change orders. Smaller projects will have a point of contact and financials will be reviewed on a monthly basis by the Advisory Group.

The undersigned acknowledge they have reviewed the Base Load Thermal
Program Business Case and agree with the approach it presents. Significant
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 40 of 309
Base Load Thermal Program 2023 - 2027
Business Case Justification Narrative Page 9 of 9
changes to this will be coordinated with and approved by the undersigned or their
designated representatives.

Signature: Date:
Print Name:
Title:
Role: Business Case Owner

Signature: Date:
Print Name:
Title:
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee
Review

Template Version: 05/28/2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 41 of 309
Noxon Rapids HVAC
Business Case Justification Narrative Template Version: 08/04/2020 Page 1 of 7
EXECUTIVE SUMMARY
The current ventilation system in the powerhouse at the Noxon Rapids Hydroelectric
Development is not operational. The system was installed in 1959 and parts are no longer available. The system needs to be replaced because the original ventilation system controls are no longer functional and have been removed. There is no cooling or heating
capacity with the current ventilation system and the current air handling system can only
be operated manually for ventilating and exhausting powerhouse air. There is no filter
system for plant make up air which results in outside smoke from wildfires and dust in the outside air from entering the plant. Additional transformers and electrical equipment planned to be installed within the powerhouse over the next 7 years will
significantly increase internal plant heat loading.
To be able to support a satisfactory work environment for plant personnel and enable sufficient cooling for critical electrical equipment, the Noxon Rapids powerhouse needs to have a new HVAC System with significant cooling and heating capacity. The service
code for this program is Electric Direct and the jurisdiction for the program is Allocated
North serving our electric customers in Washington and Idaho. Operating Noxon
Rapids safely and reliably provides our customers with low cost, reliable power while ensuring the region has the resources it needs for the Bulk Electric System (BES).
Noxon Rapids has significant operational flexibility and continues to supply clean,
reliable, and cost-effective energy for Avista customers. The capacity of Noxon Rapids
is 565 MW. The estimated cost of the project is $1.5 Million, and it is critical that this project is completed prior to the completion of the planned Noxon Rapids Generator excitation upgrade which is expected to be completed within the next 7 years. This new
HVAC system will provide the needed plant cooling of this new equipment and provide
sufficient heating, filtered ventilation and air conditioning in support of normal operations
of the plant. Without this system replacement, plant personnel will be subjected to unacceptably high internal powerhouse temperatures and critical electrical equipment will fail due to inadequate cooling.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 42 of 309
Noxon Rapids HVAC
Business Case Justification Narrative Template Version: 08/04/2020 Page 2 of 7
VERSION HISTORY
Version Author Description Date Notes
Draft Alan Lackner Initial draft of original business case 07/06/2021
1.0 Alan Lackner Updated for 2022-2026 Capital budget 07/07/2021 Not yet approved
GENERAL INFORMATION
Requested Spend Amount $ 1,500,000
Requested Spend Time Period 2 years
Requesting Organization/Department LO7/ GPSS
Business Case Owner | Sponsor Alan Lackner | Alexis Axlander |
Sponsor Organization/Department AO7/GPSS
Phase Initiation
Category Project
Driver Failed Plant & Operations
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 43 of 309
Noxon Rapids HVAC
Business Case Justification Narrative Template Version: 08/04/2020 Page 3 of 7
1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
The HVAC system at Noxon Rapids no longer functions. The 1959 heat pump has been removed due to catastrophic failure. New electrical upgrades to the generator excitation systems will introduce a significant heat load. Without a
new system the temperature in the plant will exceed acceptable temperatures
for operational personnel and critical electrical equipment.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
The driver for this business case is Failed Plant. The heating and ventilation
system is no longer functional. A new HVAC system will support the loads of critical upgrades to the electrical system, improve the working conditions of the
powerhouse with filtered air and temperature control and enable the plant to
function effectively into the future. Noxon Rapids has operational flexibility and
is operated to support energy supply, peaking power, provide continuous and
automatic adjustment of output to match changing loads, and other types of services necessary to provide a stable electric grid and to maximize value to
Avista and its customers

1.3 Identify why this work is needed now and what risks there are if not approved or is deferred
There is no cooling or heating capacity with the current ventilation system and
the current air handling system can only be operated manually for ventilating
and exhausting powerhouse air. There is no filter system for plant make
up air which results in outside smoke from wildfires and dust in the outside air from entering the plant. Planned electrical upgrades are likely to result in heat
that will cause electronic equipment to fail.

1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
The HVAC system will be designed to heat and cool the plant to adequate
working temperature for plant personnel. The system will also be designed to adequately filter outside air to protect personal and equipment from
outside contaminants. In addition, the system will be designed to compensate
for the heat load of existing and proposed critical electrical equipment. These
types of systems exist in other similar facilities. The measure of success will
be air quality and temperature control inside the powerhouse.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 44 of 309
Noxon Rapids HVAC
Business Case Justification Narrative Template Version: 08/04/2020 Page 4 of 7
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for replacement.
The metric supporting the replacement of the current system is that it is no longer functional. Air intake and exhaust are now performed manually. Make up air is not
filtered allowing outside contaminants such as smoke and dust to enter the powerhouse. Internal temperature of the plant is not controlled effectively. The
introduction of new electrical equipment which will significantly increase the heat load, will only make the problem worse.
2. PROPOSAL AND RECOMMENDED SOLUTION

Option Capital Cost Start Complete
Replace System 1,500,000 01/2023 12/2024
Do Nothing 0 01/2018

2.1 Describe what metrics, data, analysis, or information was considered
when preparing this capital request.

The failure of the system is the primary metric for justification of the project. The current system is not adequate to prevent contaminates from entering the plant,
is manually controlled, does not adequately control internal plant temperature,
and will not support critical plant electrical upgrades due to the increased heat
load. Without a proper HVAC system, operation of the plant will be put at risk
due to unacceptable working conditions for operational personnel and risk to critical electrical equipment overheating.
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include any known or estimated reductions to O&M because of this investment.

The capital cost will be spread out over two years. The first year will be primarily
design. This is estimated to be $250,000. The second year will include
equipment purchase, equipment removal, new equipment installation and commissioning. This is estimated to be $1,000,000. This will not offset
significant O&M charges because the equipment has failed so it is no longer
maintained. The risk is to personnel due to the lack of air quality control and
powerhouse temperature control and the risk to critical electrical equipment.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 45 of 309
Noxon Rapids HVAC
Business Case Justification Narrative Template Version: 08/04/2020 Page 5 of 7
2.3 Outline any business functions and processes that may be impacted (and how) by the business case for it to be successfully implemented.

The execution of this project will enable the needed upgrade of the Noxon
Rapids generator excitation replacement project. The Excitation system at the
end of its useful life. The generators cannot function without this critical
system. This critical plant systems will be at risk without adequate cooling. The temperature in the plant and inadequate air quality is also no longer be
acceptable.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Repair of the existing system is not possible.

2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
This project is expected to take two years. The effort in the first year will
be devoted system design and engineering. The effort in the second year will consist of equipment purchase, equipment removal, new equipment installation
and system commissioning. The transfer to plant will be at the end of the
second year with the completion of commissioning.

2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives, and mission statement of the organization.
Noxon Rapids affordably supports the power needs of our company and our
customers. It also assists Avista in obtaining stated green energy goals.
By taking care of this plant we support our mission of improving our customer’s lives through innovative energy solutions which includes hydroelectric
generation. By executing this project, we ensure that Noxon Rapids
is performing at a high level and serving our customers with clean, affordable,
and reliable energy.

2.7 Include why the requested amount above is considered a prudent investment, providing, or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project

2.8 Supplemental Information

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 46 of 309
Noxon Rapids HVAC
Business Case Justification Narrative Template Version: 08/04/2020 Page 6 of 7
2.8.1 Identify customers and stakeholders that interface with the business case

The primary stakeholders for this project are, the Plant Manager at Noxon
Rapids, Noxon Rapids Plant personnel, GPSS Engineering, GPSS
Construction and Maintenance, Power Supply, Environmental
Resources. Other stakeholders may be identified during project initiation.

2.8.2 Identify any related Business Cases

No current business cases.
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information

A formal Project Manager will be assigned to a project of this size. The project
will be managed within project management practices adopted by the Generation Production and Substation Support (GPSS) department. A Steering
Committee will be formed for this project. The Project Manager will manage the
project through its conclusion.

3.2 Provide and discuss the governance processes and people that will provide oversight
Management of this project will include the creation of a Steering Committee
which will include managers representing the key stakeholders involved in this
project. The project will also be executed by a formal Project Team lead by the
Project Manager.

3.3 How will decision-making, prioritization, and change requests be
documented and monitored
Once the project is initiated, reporting on scope, schedule and cost will occur
monthly. Changes in scope, schedule, or cost will be surfaced by the Project Manager to the Steering Committee for governance.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 47 of 309
Noxon Rapids HVAC
Business Case Justification Narrative Template Version: 08/04/2020 Page 7 of 7
4.APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Noxon Rapids HVAC business case
and agree with the approach it presents. Significant changes to this will be coordinated with
and approved by the undersigned or their designated representatives.
Signature: Date:
Print Name: Alan Lackner
Title: Noxon Rapids Plant Manager
Role: Business Case Owner
Signature: Date:
Print Name: Alexis Alexander
Title: Director GPSS
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 48 of 309
Peaking Generation
Business Case Justification Narrative Page 1 of 8
EXECUTIVE SUMMARY

Avista’s Peaking Generation plants offer operational flexibility and are utilized to
support energy supply needs. Thermal Peaking Generation power provides options
for Avista’s System Operations and Power Supply groups to maximize value to Avista and its customers. These plants represent more than 255 MW of power and
include Rathdrum Combustion Turbines, Boulder Park Generating Station and
Northeast Combustion Turbine, all natural gas fired power plants.
The operational availability for these generating units in these plants is paramount.
The service code for this program is Electric Direct and the jurisdiction for the program is Allocated North serving our electric customers in Washington and Idaho.
The purpose of this program is to fund smaller capital expenditures and upgrades
that are required to maintain safe and reliable operation. Maintaining these plants
safely and reliably provides our customers with low cost, reliable power while
ensuring the region has the resources it needs for the Bulk Electric System (BES).
Projects completed under this program include replacement of failed equipment,
replacement of equipment at their end of life, and small capital upgrades to plant
facilities. The business drivers for this projects in this program is a combination of
Asset Condition, Failed Plant, and addressing operational deficiencies. Most of
these projects are short in duration, typically well within the budget year, and many are reactionary to plant operational support issues. Without this funding source it
will be difficult to resolve relatively small projects concerning failed equipment and
asset condition in a timely manner. This will jeopardize plant availability and greatly
impact the value to customers and the stability of the grid.

VERSION HISTORY
Version Author Description Date Notes
Draft Mike Mecham Initial draft of original business
case 7/8/2020
1.0 Mike Mecham Peaking Generation Business
Case 6/22/2021 for 2022 - 2026
2.0 Mike Mecham Peaking Generation business case
5/26/2022 For 2023 - 2027

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 49 of 309
Peaking Generation
Business Case Justification Narrative Page 2 of 8

GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
Due to the age and use of the peaking thermal generation facilities, some core
assets, support systems and equipment are reaching the end of their useful life.
In addition, it is difficult to predict failures and unscheduled problems of operating
generating facilities. This program is critical in providing funding to support the replacement of core assets and systems that support the reliable operations of
these facilities.
1.2 Discuss the major drivers of the business case
The major drivers for this business case are Asset Condition and Failed Plant.
This program provides funding for small capital projects that are required to support the safe and reliable operation of these facilities. The flexible operations
and generating capacity of these plants maximize value for Avista and our
customers.
1.3 Identify why this work is needed now and what risks there are if not approved or is deferred.
Asset age, hours of use and failed equipment jeopardize the safe and reliable
operation of these generating facilities. If problems are not resolved in a timely
manner, the plant and plant personnel could be at risk, and failed or unavailable
assets and systems will limit plant flexibility and availability. This could have a
substantial cost impact to Avista and our customers.
Without this funding source it will be difficult to resolve relatively small projects
concerning failed equipment and asset condition in a timely manner. This will
jeopardize plant availability and greatly impact the value to customers and the
stability of the grid.
Requested Spend Amount $2,300,000
Requested Spend Time Period 5 years 2023 through 2027
Requesting Organization/Department T07 / GPSS
Business Case Owner | Sponsor Thomas Dempsey | Alexis Alexander
Sponsor Organization/Department T07 / GPSS
Phase Initiation
Category Program
Driver Asset Condition / Failed Equipment
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 50 of 309
Peaking Generation
Business Case Justification Narrative Page 3 of 8

1.4 Identify any measures that can be used to determine whether the investment would successfully deliver on the objectives and address the
need listed above.
Thermal Plants utilize plant reliability and availability metrics as well as in use
hours to determine some of the projects. Historically, this program has funded
multiple projects per year which contributed to unit availability and ensure reliability by completing hours based capital replacement or upgrades to
equipment.

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem

The historical drivers of the projects selected to be funded by the program
are a mix of Asset Condition, used hours replacement of equipment, and Failed Plant. Projects are typically completed in the calendar year. The
work is primarily performed in the 2rd and 4th quarters of the year when
outage in the Peaking Thermal Plants are scheduled, typically during run
off in the river systems or during milder weather conditions when power
prices are low and it is most opportune to have the plants unavailable for projects.

1.5.2 For asset replacement, include graphical or narrative representation
of metrics associated with the current condition of the asset that is proposed for replacement.
Being a program, this review will be performed on a project by project
basis. This decision will be made by the program Steering Committee that
consists of Thermal Management, Maintenance Engineering and Plant
Personnel.

Option Capital Cost Start Complete
Peaking Generation Program $2,250,000 01/2023 12/2027
Individual Capital Projects $2,250,000 01/2023 12/2027
Perform O&M maintenance 0
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 51 of 309
Peaking Generation
Business Case Justification Narrative Page 4 of 8
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Review of the program budget over the period of the last six years has revealed the a realistic annual budget is $500,000. In order to support the capital budget goals of the GPSS department, this budget was reduced in the short term for
years 2023 through 2027 by 10%. Projects with lower risk will be delayed
through this period.
The drivers of the projects selected to be funded by this program are mix of use hours based replacement, Asset Condition and Failed Plant. Resolving issues encountered in operating these plants in a timely manner benefits the customers
with providing safe, reliable, low cost power which supports the needs of Bulk
Electric System and provides value to Avista and our customers.

2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.

The projects in this program typically take place during the outages which are in
the late spring and fall of each year. Most of the capital is deployed in the 2rd
and 4th quarter of each year.
If capital funds were not available for the projects in this program, reliability of the plant would decrease and more O&M would need to be performed to repair
aging equipment instead of replacement. Due to the nature of the smaller
Capital projects covered under the Peaking Generation Program, forced
outages and reliability are difficult to quantify. Should forced outages occur due
to the inability to cover Capital projects under this program, daily estimated Power Supply outage costs associated with the Peaking Generation facilities
covered under this Program are estimated to be:
Rathdrum CT: $3,800
Boulder Park GS: $1,300
Northeast CT: $1,200
(refer to 20220825 Thermal Daily Outage Cost Estimation Tool CONFIDENTIAL.xlsx)

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 52 of 309
Peaking Generation
Business Case Justification Narrative Page 5 of 8

2.3 Outline any business functions and processes that may be impacted (and how) by the business case for it to be successfully implemented.

These projects vary in size and support needed from the Department and key
stakeholders. The larger projects require formal project management with a
broader stakeholder team. Medium to small projects can be implemented by a project engineer or project coordinator and many cases can be handled by
contractors managed by the Thermal personnel, including Management and
engineering. All of these projects are prioritized and coordinated by the broader
support team.

2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
One alternative would be to create business cases using the business case
template and process for each of these small projects. There are typically 10 to 15 projects a year funded by the program. This would overload the Capital
Budget Process with small to medium projects whose governance can be
effectively handled by the Thermal Group. These projects are specific to these
plants and the leadership in the Thermal Group understand best the nature and
context of these projects.
These projects are, at times, unpredictable. It would be difficult to forecast
unforeseen events such as equipment failures and identify critical asset
condition that could effectively be put in the annual capital plan.
Another alternative would be to attempt to repair this equipment instead of
replacing critical assets at the end of their lifecycle. This will be unacceptably expensive and older equipment will become more and more unreliable until it
becomes obsolete. Operating in a run-to-failure mode is proven to be an
unsuccessful approach and subjects Avista and its customers to unacceptable
risk.

2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
spend, and transfers to plant by year.

The projects in this program typically take place during the outages for the Peaking Thermal Plants, which are typically in the spring and fall of each year. Some projects may have the ability to be performed during non-outage times.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 53 of 309
Peaking Generation
Business Case Justification Narrative Page 6 of 8
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.

The purpose of this program is to provide funding to small to medium size projects with the objective of keeping our Peaking Generation plants reliable
and available to support the power needs of our company and our customers
affordably. By doing this we support our mission of improving our customer’s
lives through innovative energy solutions which includes Peaking Thermal generation. By executing the projects funded by the program, we insure that Peaking Generation Facilities are performing at a high level and serving our
customers with affordable and reliable energy.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In addition, please explain how the investment prudency will be reviewed and re-evaluated throughout the project
Review of the program budget has revealed that a realistic annual budget is $500,000.
The 5 year historical average spend in the Peaking Generation Program is $460,000. In order to support the capital budget goals of the GPSS department, this budget was reduced in the short term for years 2023 through 2027 by 10% per year. Projects with
lower risk will be delayed through this period.
The drivers of the projects selected to be funded by this program are mix Asset
Condition and Failed Plant. Resolving issues encountered in operating these plants in
a timely manner benefits the customers with providing safe, reliable, low cost power which supports the needs of Bulk Electric System and provides value to Avista and our
customers.

2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case

The list of primary customers and stakeholders includes: GPSS, Environmental
Resources, Power Supply, Systems Operations, ET, and electric customers in
Washington and Idaho.

2.8.2 Identify any related Business Cases

None

3.1 Advisory Group Information
The Advisory Group for this program consists of the GPSS Asset Management and
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 54 of 309
Peaking Generation
Business Case Justification Narrative Page 7 of 8
Compliance Engineering team, Thermal Plant Operations Manager, Thermal
Maintenance Engineering and the Manager of Thermal Operations and Maintenance.
3.2 Provide and discuss the governance processes and people that will
provide oversight
Projects are proposed through various organizations in Generation Production
and Substation Support (GPSS) and through key stakeholder such as
Environmental Resources, and Safety and Security. The projects are vetted by the Thermal Advisory Group. With the assistance of Operations, Construction
and Maintenance and Engineering, projects are evaluated to determine
available options, confirm prudency, and bring potential solutions forward.
This same vetting process is followed for emergency projects and may included
other key stakeholders. Over the course of the year, the program is actively managed by the Thermal Operations Manager, with the assistance of the
Advisory Group. This includes monthly analysis of cost and project progress
and reporting of expected spend.
3.3 How will decision-making, prioritization, and change requests be documented and monitored
Each project request will be evaluated by the Advisory Group which will include
the scope, cost and risk associated with the project. The project will be
evaluated based on the impact or potential impact of the operation of the
Peaking Generation plants. The selection and approval of the project will be
based on the experience and consensus of the Advisory Group.
Depending on the size of the project, a Project Manager or Project Coordinator
may be assigned. They will follow the project management process for reporting
and identifying and executing change orders. Smaller projects will have a point
of contact and financials will be review on a monthly basis by the Advisory
Group.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 55 of 309
Peaking Generation
Business Case Justification Narrative Page 8 of 8
The undersigned acknowledge they have reviewed the Peaking Generation
Program business case and agree with the approach it presents. Significant
changes to this will be coordinated with and approved by the undersigned or their designated representatives.

Signature: Date:
Print Name:
Title:
Role: Business Case Owner

Signature: Date:
Print Name:
Title:
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 56 of 309
Asset Monitoring Systems
Business Case Justification Narrative Template Version: 04.21.2022 Page 1 of 5
EXECUTIVE SUMMARY

The yearly amount of $250k is based on Asset Monitoring Systems that are needed to track the condition of our Assets. These systems are in both our Hydro and Thermal Generation Plants. They are not part of the Generation Control System that is used for
real-time control and monitoring. There is a need to update the existing systems and
install new systems to monitor the condition of our Assets. These Asset Monitoring
Systems are used to influence our Maintenance and Capital planning. The budget amounts are based on 2022 quotes for replacing, updating, and installing new systems. These systems will interface with the corporate network and therefore need to be updated
periodically to keep up with changing software and security needs.
The risk of not approving this yearly amount will cause our Asset Monitoring Systems to
become obsolete and therefore move us back to a reactionary place upon assets failure.
This business case has been reviewed and approved by GPSS Management.

VERSION HISTORY
Version Author Description Date Notes
1.0 Glen Farmer Draft and review 4/8/2022
2.0 Glen Farmer SCRUM Update and Approval to move
forward. 5/18/2022
2.1 Glen Farmer Submit for Approval 6/1/2022
2.2 Glen Farmer Finish Business Case Info 8/23/2022

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 57 of 309
Asset Monitoring Systems
Business Case Justification Narrative Template Version: 04.21.2022 Page 2 of 5
GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 The Generation Plant Assets have asset monitoring that can give us indication
of performance and values that can give us trending condition of the asset.
These systems become outdated or obsolete based on the manufactures software being unsupported. Also, some systems have a limited number of
testing that can be performed based on the system parameters.
1.2 The driver for these Asset Monitoring Systems is Asset Condition. When these
systems are working correctly was can use them to give us indication of
degrading condition. From there we can start the process of putting a Business Case together before the Asset fails. In the past we would wait until the Asset
failed, then we would apply a temporary fix to give us time to start the Business
Case process.

1.3 The risk, if not approved, is we would be looking at an indicator of failure, then
doing a temporary fix then replace. This takes time to get things approved and
in the budget. Our budget is fixed and when failures happen then that moves
out other projects.

1.4 We have used these Asset Monitoring Systems to give us indication of the Asset
Condition. Based on the trending of the data the condition of the asset will at
some point be switched off-line when the Monitoring and Control Systems gives us indication of a failure or potential failure. In the past we have reduced the
capacity of system or the runtime of the system to give us some time to get a
replacement project going. In these cases, the megawatt output is normally
reduced, and we are hoping that it will make it until the fix can be engineered,
procured, and installed.

Requested Spend Amount $250,000
Requested Spend Time Period Per year
Requesting Organization/Department G07
Business Case Owner | Sponsor Glen Farmer | Alexis Alexander
Sponsor Organization/Department GPSS
Phase Initiation
Category Program
Driver Asset Condition
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 58 of 309
Asset Monitoring Systems
Business Case Justification Narrative Template Version: 04.21.2022 Page 3 of 5
1.5 Supplemental Information
1.5.1 Manufactures letters indicating that product support will no longer be available is the first indication that we receive. When that happens then
we can no longer update the computer systems that is running the
software. At some point the computer system must be upgraded which
brings about a new operating system. The new operating system requires
a new interface box, and the software must be upgraded to run on the latest operating system.
2. PROPOSAL AND RECOMMENDED SOLUTION
The recommended solution is to update the Asset Monitoring Systems with the latest
manufactures supported equipment to stay current with the interface boxes and
updated software so that the computers can be upgraded as they become obsolete.

Option Capital Cost Start Complete
Update the Asset Monitoring System with latest
Manufactures supported equipment.
$250,000/year 01/2023 12/2023
Don’t replace system and disconnect from network $10,000/year 01/2023 12/2023
Hire Manufacture to run data collection and provide
recommendation report.
$375,000/year 01/2023 12/2023
2.1 Working with the manufactures of the equipment we requested alternatives for keeping the systems working and updated. To do this we need to purchase the
manufactures supported systems. Normally we can save the database and load
that in the new system so we can continue the trending of the asset. Sometimes
we must start over on the trending. We use industrial standard curves and data points to quantify the asset condition.

2.2 The capital cost will go to the systems that have already failed or have been
obsolete and are no longer collecting data. We will concentrate on one Unit per
year or one type of system per year.

2.3 The Business Unit will use these Asset Monitoring Systems to trend the Asset
Condition which will provide time for the Business Cases to be developed ranked and prioritized and put into our 5-year plan.

2.4 The alternatives of “Don’t replace system and disconnect from network” is a risk
of not being able to indicate when we are having issues with an asset. That is
fine if we want to run to failure. If that is the case, then upon failure we must figure out what is not going to be done in our plan. That effects manpower and
budget changes. Once approved then we must start the project process.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 59 of 309
Asset Monitoring Systems
Business Case Justification Narrative Template Version: 04.21.2022 Page 4 of 5
The alternative of “HIRE MANUFACTURE TO RUN DATA COLLECTION AND PROVIDE
RECOMMENDATION REPORT” is a risk because it is just a snapshot of the equipment condition at the time the data is taken.

2.5 Given that our install window is the last couple months of each year the material
will be purchased in the first year and the install and commissioning will happen
in the following year.
2.6 To be reliable we need to have these types of systems to give us data on the
condition trends of the Assets.

2.7 As we mature our Asset Management plans these systems will be key to
showing when we need to move forward with a capital replacement. They can also give us indication of what Unit needs attention during the maintenance
cycles. We will be looking at the data from these systems on a quarterly basis
and do a report yearly.

2.8 Supplemental Information

2.8.1 The customers and stakeholders of these systems is the Asset Management and
Compliance Engineering team and Operations.

3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
The steering committee will be the Asset Management & Compliance
Engineering group. Each project will be discussed and prioritized with other
similar projects.
3.2 The governance oversight will be provided by Sr. GPSS Management.
3.3 Decision making on projects will be bast on failed equipment and prioritized
based on megawatts output. Changes will be documented in a spreadsheet for
tracking the projects.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 60 of 309
Asset Monitoring Systems
Business Case Justification Narrative Template Version: 04.21.2022 Page 5 of 5
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Asset Monitoring Systems business
case and agree with the approach it presents. Significant changes to this will be coordinated
with and approved by the undersigned or their designated representatives.

Signature: Date: 8/23/2022
Print Name: Glen Farmer
Title: Asset Management & Compliance Engineering Manager
Role: Business Case Owner

Signature: Date:
Print Name: Alexis Alexander
Title: Director, GPSS
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 61 of 309
Base Load Hydro
Business Case Justification Narrative Page 1 of 8
EXECUTIVE SUMMARY

Avista’s Base Load Hydro plants are all located on the upper Spokane River and
are “run of river” plants which means they have little to no storage capacity and their
operation is subjected to the flow in the Spokane River and the lake level
requirements of Lake Coeur d’Alene, upstream of the plants. The facilities
considered in this program are: Post Falls, Upper Falls, Monroe Street and Nine
Mile Hydroelectric Developments. This program also includes capital projects at the
Generation Control Center and on the Generation Control Network. It can also
include some projects at the Post Street 115kV Substation where the two downtown
hydro plants are tied into the grid.
The operational availability for these generating units in these plants is paramount.
The service code for this program is Electric Direct and the jurisdiction for the
program is Allocated North serving our electric customers in Washington and Idaho.
The purpose of this program is to fund smaller capital expenditures and upgrades
that are required to maintain safe and reliable operation. Maintaining these plants
safely and reliably provides our customers with low cost, reliable power while
ensuring the region has the resources it needs for the Bulk Electric System (BES).
Projects completed under this program include replacement of failed equipment and
small capital upgrades to plant facilities. The business drivers for the projects in this
program are a combination of Asset Condition, Failed (or Failing) Plant, and
addressing operational deficiencies. Most of these projects are short in duration,
typically well within the budget year, and many are reactionary to plant operational
support issues. Without this funding source it will be difficult to resolve relatively
small projects concerning failed equipment and asset condition in a timely manner.
This will jeopardize plant availability and greatly impact the value to our customers
and the stability of the grid.
Due to the age of the facilities more and more critical assets, support systems and
equipment are reaching the end of their useful life. This program is critical in
continuing to support asset management program lifecycle replacement schedules.
The annual cost of this program is variable and depends on discovery of unfavorable
asset condition and the unpredictability of equipment failures.

VERSION HISTORY
Version Author Description Date Notes
Draft Bob Weisbeck Initial draft of original business case 6/29/20
1.0 Bob Weisbeck Updated for 2022-2026 Capital Plan
2.0 Bob Weisbeck Updated for 2023-2027 Capital Plan

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 62 of 309
Base Load Hydro
Business Case Justification Narrative Page 2 of 8

GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
Due to the age and continuous use of the Base Load Hydro facilities, more and
more critical assets, support systems and equipment are reaching the end of their
useful life. In addition, it is difficult to predict failures and unscheduled problems
of operating hydroelectric generating facilities. This program is critical in
providing funding to support the replacement of critical assets and systems that
support the reliable operations of these critical facilities.
1.2 Discuss the major drivers of the business case
The major drivers for this business case are Asset Condition and Failed Plant.
This program provides funding for small capital projects that are required to
support the safe and reliable operation of these hydro facilities. The cost-
effective operations and generating capacity of these plants, maximize value for
Avista and our customers.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred.
Critical asset condition and failed equipment jeopardize the safe and reliable
operation of these generating facilities. If problems are not resolved in a timely
manner, the plant and plant personnel could be at risk and failed or unavailable
critical assets and systems will limit plant availability. This could have a
substantial cost impact to Avista and our customers.
Without this funding source it will be difficult to resolve relatively small projects
concerning failed equipment and asset condition in a timely manner. This will
jeopardize plant availability and greatly impact the value to customers and the
stability of the grid.
Requested Spend Amount $5,125,000
Requested Spend Time Period 5 years
Requesting Organization/Department C07 / GPSS
Business Case Owner | Sponsor Bob Weisbeck | Alexis Alexander
Sponsor Organization/Department C07 / GPSS
Phase Initiation
Category Program
Driver Asset Condition / Failed Equipment
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 63 of 309
Base Load Hydro
Business Case Justification Narrative Page 3 of 8

1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
Plant reliability and availability is measured as well as the frequency and nature
of forced outages. These metrics will contribute to prioritizing the projects in this
program. Historically, this program has funded multiple projects per year which
contributed to high unit availability.

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem

The historical drivers of the projects selected to be funded by the program
are a mix of Asset Condition, approximately 66% and Failed Plant,
approximately 34%. Projects are typically completed within the calendar
year.

1.5.2 For asset replacement, include graphical or narrative representation
of metrics associated with the current condition of the asset that is
proposed for replacement.
Being a program, this review will be performed on a project by project
basis. This decision will be made by the program Advisory Committee.

Option Capital Cost Start Complete
Base Hydro Program $5,125,000 01/2023 12/2027
Individual Capital Projects $5,125,000 01/2023 12/2027
Perform O&M maintenance 0
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 64 of 309
Base Load Hydro
Business Case Justification Narrative Page 4 of 8
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Review of the program budget over the period of the last six years has revealed
a realistic annual budget is $1,025,000, especially based on the age of the Base
Load Hydro plants.
The drivers of the projects selected to be funded by this program are mix Asset
Condition (approximately 66%) and Failed Plant (34%). Resolving issues
encountered in operating these plants in a timely manner benefits the customers
with providing safe, reliable, low cost power which supports the needs of Bulk
Electric System and provides value to Avista and our customers.

2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.

The annual budget program, based on review of the past six years, is
approximately $1,025,000. Projects with the lowest risk will be postponed during
this period. The projects in this program typically take place within the calendar.
If capital funds were not available for the projects in this program, reliability of
the plant would decrease, and more O&M would need to be performed to repair
aging equipment instead of replacement. This would be an unacceptable and
substantial increase in the O&M expenditures.

2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.

These projects vary in size and support needed based on the requests from the
department and from key stakeholders. The larger projects require formal
project management with a broader stakeholder team. Medium to small projects
can be implemented by a project engineer or project coordinator and many
cases can be handled by contractors managed by the regional personnel. All
these projects are prioritized and coordinated by the broader support team.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 65 of 309
Base Load Hydro
Business Case Justification Narrative Page 5 of 8
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
One alternative would be to create business cases using the business case
template and process for each of these small projects. There are typically 20
projects a year funded by the program. This would overload the Capital Budget
Process with small to medium projects whose governance can be effectively
handled by the hydro organization. These projects are specific to these plants
and the leadership in hydro operations understand the best the nature and
context of these projects.
These projects are somewhat unpredictable. It would be difficult to forecast
unforeseen events such as equipment failures and identify critical asset
condition that could effectively be put in the annual capital plan.
Another alternative would be to attempt to repair this equipment instead of
replacing critical assets at the end of their lifecycle. This will be unacceptably
expensive and older equipment will become more and more unreliable until it
becomes obsolete. Operating in a run-to-failure mode is proven to be an
unsuccessful approach and subjects Avista and its customers to unacceptable
risk.

2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
spend, and transfers to plant by year.

The projects in this program typically take place during the outages for the Hydro
Plants which are typically in the summer and fall of each year. Some projects
may have the ability to be performed in the first two quarters of the year. Work
performed in and around the dams that require outages is safer and more cost
effective after run off has occurred in the rivers.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.

The purpose of this program is to provide funding to small to medium size
projects with the objective of keeping our hydroelectric plants reliable and
available. This enables these plants to affordably support the power needs of
our company and our customers. By taking care of these facilities we support
our mission of improving our customer’s lives through innovative energy
solutions which includes hydroelectric generation. By executing the projects
funded by the program, we ensure that hydro facilities are performing at a high
level and serving our customers with affordable and reliable energy.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 66 of 309
Base Load Hydro
Business Case Justification Narrative Page 6 of 8
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
Review of the program budget has revealed that a realistic annual budget is
$1,025,000. Projects with the lowest risk will be postponed during this period. The
projects in this program typically take place within the calendar.
The drivers of the projects selected to be funded by this program are mix Asset
Condition (approximately 66%) and Failed Plant (34%). Resolving issues encountered
in operating these plants in a timely manner benefits the customers with providing safe,
reliable, low cost power which supports the needs of Bulk Electric System and provides
value to Avista and our customers.

2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case

The list of primary customers and stakeholders includes: GPSS, Environmental
Resources, Power Supply, Systems Operations, ET, and electric customers in
Washington and Idaho.

2.8.2 Identify any related Business Cases

3.1 Advisory Group Information
The Advisory Group for this program consists of the four regional Hydro Managers and
the Sr Manager of Hydro Operations and Maintenance.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 67 of 309
Base Load Hydro
Business Case Justification Narrative Page 7 of 8
3.2 Provide and discuss the governance processes and people that will
provide oversight
Projects are proposed through various organizations in Generation Production and
Substation Support (GPSS) and through key stakeholder such as Environmental
Resources, Dam Safety, and Safety and Security. The projects are vetted by the Hydro
Advisory Group. With the assistance of Operations, Construction and Maintenance
and Engineering, projects are evaluated to determine available options, confirm
prudency, and bring potential solutions forward.
This same vetting process is followed for emergency projects and may include other
key stakeholders. Over the course of the year, the program is actively managed by the
Sr. Manager of Hydro Operations, with the assistance of the Advisory Group. This
includes monthly analysis of cost and project progress and reporting of expected spend.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
Each project request will be evaluated by the Advisory Group which will include
the scope, cost and risk associated with the project. The project will be
evaluated based on the impact or potential impact of the operation of the
Regulating Hydro plants. The selection and approval of the project will be based
on the experience and consensus of the Advisory Group.
Depending on the size of the project, a Project Manager or Project Coordinator
may be assigned. In this case, the project management process is followed for
reporting and identifying and executing change orders. Smaller projects will
have a point of contact and financials will be reviewed on a monthly basis by the
Advisory Group.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 68 of 309
Base Load Hydro
Business Case Justification Narrative Page 8 of 8

The undersigned acknowledge they have reviewed the Based Load Hydro Program
business case and agree with the approach it presents. Significant changes to this
will be coordinated with and approved by the undersigned or their designated
representatives.

Signature: Date:
Print Name:
Title:
Role: Business Case Owner

Signature: Date:
Print Name:
Title:
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
Bob Weisbeck
05-23-2022
Manager, Hydro Ops and Maintenance
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 69 of 309
Cabinet Gorge HVAC
Business Case Justification Narrative Page 1 of 8
EXECUTIVE SUMMARY

The current ventilation system in the powerhouse at the Cabinet Gorge Hydroelectric
Development (Cabinet Gorge) is still the original system and equipment that was installed
in 1952. The system needs to be replaced because the original ventilation system controls are no longer functional and have been removed. There is no cooling capacity
with the current ventilation system and the current air handling system can only be
operated manually for ventilating and exhausting powerhouse air. There is no filter system
for plant make up air which results in outside smoke from wildfires and dust in the outside
air from entering the plant. The current summer temperatures in the powerhouse routinely rise to 90°F and additional transformers and electrical equipment planned to be installed
within the powerhouse over the next three years will significantly increase internal plant
heat loading.

To be able to support a satisfactory work environment for plant personnel and enable sufficient cooling for critical electrical equipment, the Cabinet Gorge powerhouse needs
to have a new HVAC System with significant cooling capacity. The service code for this
program is Electric Direct and the jurisdiction for the program is Allocated North serving
our electric customers in Washington and Idaho. Operating Cabinet Gorge safely and
reliably provides our customers with low cost, reliable power while ensuring the region has the resources it needs for the Bulk Electric System (BES).

Cabinet Gorge has operational flexibility and is operated to support energy supply,
peaking power, provide continuous and automatic adjustment of output to match the
changing system loads, and other types of services necessary to provide a stable electric grid and to maximize value to Avista and its customers. The capacity of this plant alone
is 270 MW. The estimated cost of the project is $1.75 Million, and it is critical that this
project is completed. The new Station Service upgrade which is expected to be completed
in 2023 will produce an additional heat load in the plant. This new HVAC system will
provide the needed plant cooling of this new equipment and provide sufficient heating, ventilation and air conditioning in support of normal operations of the plant. Without this
system replacement, plant personnel will be subjected to unacceptably high internal
powerhouse temperatures and critical electrical equipment will fail due to inadequate
cooling.
VERSION HISTORY
Version Author Description Date Notes
Draft Bob Weisbeck Initial draft of original business case 6/30/2020
1.0 Bob Weisbeck Updated Approval Status 6/30/2020 Full amount approved
2.0 Chris Clemens Updated for the 2022-2026 SCRUM 7/6/2021 5-year Capitol
Planning Process
2.0 Chris Clemens Updated for the 2023-2027 SCRUM
8/23/2022
5-year Capitol
Planning Process
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 70 of 309
Cabinet Gorge HVAC
Business Case Justification Narrative Page 2 of 8

GENERAL INFORMATION

1. BUSINESS PROBLEM

1.1 What is the current or potential problem that is being addressed?
The HVAC system at Cabinet Gorge is nearly 70 years old and is no longer in working order. The controls have failed and have been removed. The system
is operated manually and currently only provides unfiltered outside air which is
problematic during wildfire season and the introduction of dust in the
powerhouse. The temperature in the plant is not regulated effectively with summertime temperatures reaching up to 90°F inside the powerhouse. New electrical upgrades to the station service will introduce a significant heat load.
Without a new system the temperature in the plant will exceed acceptable
temperatures for operational personnel and critical electrical equipment.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer.
The driver for this business case is Failed Plant. The heating and ventilation system is no longer functional. A new HVAC system will support the loads of critical upgrades to the electrical system, improve the working conditions of the
powerhouse with filtered air and temperature control and enable the plant to
function effectively into the future. Cabinet Gorge has operational flexibility and
is operated to support energy supply, peaking power, provide continuous and automatic adjustment of output to match changing loads, and other types of services necessary to provide a stable electric grid and to maximize value to
Avista and its customers.

Requested Spend Amount $1,750,000
Requested Spend Time Period 2 years
Requesting Organization/Department D07/GPSS
Business Case Owner | Sponsor Chris Clemens | Alexis Alexander
Sponsor Organization/Department A07/GPSS
Phase Initiation
Category Project
Driver Failed Plant & Operations
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 71 of 309
Cabinet Gorge HVAC
Business Case Justification Narrative Page 3 of 8
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
There is no cooling capacity with the current ventilation system and the current air handling system can only be operated manually for ventilating and exhausting powerhouse air. There is no filter system for plant make up air which
results in outside smoke from wildfires and dust in the outside air from entering
the plant. The current summer temperatures in the powerhouse routinely rise to
90°F and additional transformers and electrical equipment planned to be installed within the powerhouse as part of the Station Service Upgrade Project over the next three years will significantly increase internal plant heat loading.
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
The HVAC system will be designed to heat and cool the plant to adequate working temperature for plant personnel. The system will also be designed to
adequately filter outside air to protect personal and equipment from outside
contaminants. In addition, the system will be designed to compensate for the
heat load of existing and proposed critical electrical equipment. These types of systems currently exist in other facilities similar to this powerhouse. The measure of success will be air quality and temperature control inside the
powerhouse.

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the
problem.

1.5.2 For asset replacement, include graphical or narrative representation of metrics associated with the current condition of the asset that is
proposed for replacement.
The metric supporting the replacement of the current system is that it is
no longer functional. Air intake and exhaust are now performed manually. Make up air is not filtered allowing outside contaminants such as smoke and dust to enter the powerhouse. Internal temperature of the plant is not
controlled effectively. The introduction of new electrical equipment which
will significantly increase the heat load, will only make the problem worse.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 72 of 309
Cabinet Gorge HVAC
Business Case Justification Narrative Page 4 of 8
Option Capital Cost Start Complete
Replace with new HVAC System $1,750,000 01 2023 12 2024

2.1 Describe what metrics, data, analysis or information was considered when preparing this capital request.
The failure of the system is the primary metric for justification of the project. The
current system is not adequate to prevent contaminates from entering the plant,
is manually controlled, does not adequately control internal plant temperature
and will not support critical plant electrical upgrades due to the increased heat load. Without a proper HVAC system, operation of the plant will be put at risk due to unacceptable working conditions for operational personnel and risk to
critical electrical equipment overheating.

2.2 Discuss how the requested capital cost amount will be spent in the current year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.

The capital cost will be spread out over two years. The first year will be primarily design and sourcing of the equipment.This is estimated to be $250,000. The
second year will include equipment removal, new equipment installation and
commissioning.This is estimated to be $1,500,000.This will not offset significant
O&M charges because the equipment has failed so it is no longer maintained.
The risk is to personnel due to the lack of air quality control and powerhouse temperature control and the risk to critical electrical equipment.

2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.

The execution of this project will enable the needed upgrade of the Cabinet Gorge Station Service project. The Station Service at this plant is at the end of
its useful life. The plant cannot function without this critical system. This critical
system will be at risk without adequate cooling. The temperature in the plant
and inadequate air quality is also no longer be acceptable.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 73 of 309
Cabinet Gorge HVAC
Business Case Justification Narrative Page 5 of 8
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
The repair of the existing unit was considered, but the age of the equipment and the removal of failed components prevent this from being a feasible option. In addition, even if this system could be repaired, the heat load of the plant will
increase with critical electrical system upgrades which are planned in the next
three years.
The only feasible alternative is to install a HVAC system which will handle the new electrical loads, filter the air properly, and adequately control the temperature in the powerhouse.

2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer. spend, and transfers to plant by year.

This project is expected to take two years. The effort in the first year will be
devoted design and equipment sourcing. The effort in the second year will
consist of equipment removal, new equipment installation and system commissioning. The transfer to plant will be at the end of the second year with the completion of commissioning.

2.6 Discuss how the proposed investment aligns with strategic vision, goals, objectives and mission statement of the organization.

Cabinet Gorge affordably supports the power needs of our company and our
customers. By taking care of this plant we support our mission of improving our
customer’s lives through innovative energy solutions which includes hydroelectric generation. By executing this project, we ensure that Cabinet Gorge is performing at a high level and serving our customers with affordable
and reliable energy.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 74 of 309
Cabinet Gorge HVAC
Business Case Justification Narrative Page 6 of 8
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed and re-evaluated throughout the project
Industrial HVAC systems of this size and complexity fall into this range of cost.
The system will need to be designed based on the estimated heat load and the
air make up systems will need to be custom made to fit this powerhouse.
A formal Project Manager will be assigned to a project of this size. The project will be managed within project management practices adopted by the Generation Production and Substation Support (GPSS) department. This
includes the creation of a Steering Committee and a formal Project Team. Once
the project is initiated, reporting on scope, schedule and cost will occur monthly.
Changes in scope, schedule, or cost will be surfaced by the Project Manager to the Steering Committee for governance. The Project Manager will manage the project through its conclusion.

2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
The primary stakeholders for this project are, the Hydro Regional Manager
at Cabinet Gorge, Cabinet Gorge Plant personnel, GPSS Engineering,
GPSS Construction and Maintenance, Power Supply, Environmental Resources. Other stakeholders may be identified during project initiation.

2.8.2 Identify any related Business Cases
This project will need to be completed prior to or along with the completion of the Cabinet Gorge Station Service Project. The HVAC system needs to be in place to support the increased heat load due to the critical
electrical system that will be part of the station service system.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 75 of 309
Cabinet Gorge HVAC
Business Case Justification Narrative Page 7 of 8
3.1 Steering Committee or Advisory Group Information
A formal Project Manager will be assigned to a project of this size. The project
will be managed within project management practices adopted by the Generation Production and Substation Support (GPSS) department. A Steering Committee will be formed for this project. The Project Manager will manage the
project through its conclusion.
3.2 Provide and discuss the governance processes and people that will
provide oversight
Management of this project will include the creation of a Steering Committee which will include managers representing the key stakeholders involved in this
project. The project will also be executed by a formal Project Team lead by the
Project Manager.
3.3 How will decision-making, prioritization, and change requests be documented and monitored
Once the project is initiated, reporting on scope, schedule and cost will occur
monthly. Changes in scope, schedule, or cost will be surfaced by the Project
Manager to the Steering Committee for governance.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 76 of 309
Cabinet Gorge HVAC
Business Case Justification Narrative Page 8 of 8

The undersigned acknowledge they have reviewed the Cabinet Gorge HVAC business case and agree with the approach it presents. Significant changes to this
will be coordinated with and approved by the undersigned or their designated
representatives.

Signature: Date:
Print Name: Chris Clemens
Title: Cabinet Gorge Plant Manager
Role: Business Case Owner

Signature: Date:
Print Name: Alexis Alexander
Title: Director GPSS
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 77 of 309
Cabinet Gorge Station Service
Business Case Justification Narrative Page 1 of 6
EXECUTIVE SUMMARY

Cabinet Gorge Hydroelectric Development (HED) is the second largest such generating
plant in Avista’s hydropower fleet. It is located on the Clark Fork River in Bonner County,
Idaho. With four generators, it has a 270 MW output capacity. Built in 1952, the plant has
retained most of its original equipment which is now aging and at end of life. In particular,
the Station Service equipment is vital to the plant’s continued operation. Station Service
equipment includes Load Centers, Transformers, Switchgear, Power Centers and Neutral
Grounding Resisters. This equipment is used to operate the generating plant. It includes
energy consumed for plant lighting, power, and auxiliary facilities in support of the
electricity generation system.

It is recommended that this aging equipment be replaced to ensure the continued safe
operation of the plant. Safe operation of the plant contributes to grid optimization,
reliability and personnel safety. Power generation provided from within Avista’s fleet
maximizes the use of its own assets on behalf of its customers rather than having to
procure them from other providers thereby keeping costs down for Avista’s customers. As many other equipment upgrades are underway at Cabinet Gorge, the timing of these
Station Service replacements has been coordinated in order to reduce plant outages.
Please refer to the Cabinet Gorge Unit 3 and 4 Protection & Control Upgrade projects. In
terms of risk, if this equipment is not upgraded, failure poses substantial hazards not only
to the plant’s operation but also to plant personnel as failed equipment can cause significant bodily injury and fire danger.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 78 of 309
Cabinet Gorge Station Service
Business Case Justification Narrative Page 2 of 6
VERSION HISTORY
Version Author Description Date Notes
1.0 Glen Farmer Initial draft of original business case 8/1/2020
2.0 Chris Clemens Updated for the 2022-2026 SCRUM 7/6/2021 5-year Capitol Planning
Process
3.0 Chris Clemens Updated for the 2023-2027 SCRUM 8/23/2022 5-year Capitol Planning
Process

GENERAL INFORMATION
Requested Spend Amount 2021 $750,000 (approved)
Requested Spend Amount 2022 $5,371,800 (approved)
Requested Spend Amount 2023 $5,152,937 (requested)
Requested Spend Time Period 3 years
Requesting Organization/Department D07/GPSS
Business Case Owner | Sponsor Chris Clemens | Alexis Alexander
Sponsor Organization/Department A07/GPSS
Phase Execution
Category Project
Driver Asset Condition
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 79 of 309
Cabinet Gorge Station Service
Business Case Justification Narrative Page 3 of 6
1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
Original equipment; manufacturers no longer support; can’t add anything to
Station Service due to capacity limitations; decrease in reliability and safety from
the standpoint of protecting equipment and personnel.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer.
Major drivers for this project include improved reliability and safety; manufacturers support for maintenance; address additions to capacity and
obtain better insight into each individual feeder or starter.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred.
Station Service components are being designed the from 13kV level to the lowest voltage and approaching it as one system rather than individually
addressing equipment failures as they arise.
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the need listed above.
Reduced failures and increased reliability would demonstrate successful
delivery on identified objectives.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem.
No studies were performed however, in the 2000’s, additional protection
was added to the existing main feeders to improve safety. Feeder
breakers were rebuilt in 2006. It was identified that the Power Centers and
Load Centers were in poor condition and without replacement parts, as equipment failed, we would have to take either the Load Centers or Power Centers offline to attach disconnects to the bus. This would allow us to
place equipment back in service but would leave us exposed from a
protection standpoint.
1.5.2 For asset replacement, include graphical or narrative representation of metrics associated with the current condition of the asset that is proposed for replacement. N/A

Option Capital Cost Start Complete
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 80 of 309
Cabinet Gorge Station Service
Business Case Justification Narrative Page 4 of 6
Address Emergency Side of Station Service $2,500,000 2017 2021
Power Center A and associated equipment $5,371,800 01/2022 12/2022
Power Center B and associated equipment $5,152,937 01/2023 12/2023
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
When preparing this capital request for Emergency Loads, Power Centers and Load Centers, we worked with Power Engineers to develop a game plan and preliminary budgets.
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include any known or estimated reductions to O&M as a result of this investment.
The proposed solution is to address Station Service as a whole; to help with
budget and resources, the plan is to address the emergency loads first followed
by Power Center A and then Power Center B. The diagram below shows what
would be replaced in Power Center B.

This approach allows for minimal outage to loads as equipment is replaced.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 81 of 309
Cabinet Gorge Station Service
Business Case Justification Narrative Page 5 of 6
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
Improve operational insight into the Station Service from the standpoint of voltage, current, run time and starts.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Due to the number and variety of projects taking place at Cabinet Gorge, we
were faced with prioritization of projects to ensure the best use of resources, meeting budgets and minimizing outage impacts as well as addressing safety concerns. This caused us to re-evaluate the implementation of this project over
several years which is stated above.
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer. The project is broken into three phases to allow for budgets, resources and in-service dates to correspond to work completed.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Upgrading the Station Service equipment at Cabinet Gorge contributes to the Safe and Responsible design, construction, operation and maintenance of
Avista’s generating fleet.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed and re-evaluated throughout the project.
We ranked this project based on a ranking matrix to ensure prudent
consideration of costs, scheduling and personnel resources.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case.
Electric shop, mechanical shop, relay shop, engineering, Operations, SCADA,
Protection, Environmental, Project Management and Power Supply.
2.8.2 Identify any related Business Cases
Cabinet Gorge HVAC Replacement Project
Cabinet Gorge 15kV Bus Replacement
3.1 Steering Committee or Advisory Group Information
The Steering Committee consists of the following members: Manager of Project
Delivery, Manager of Maintenance and Construction, Manager, Manager of Hydro Operations & Maintenance.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 82 of 309
Cabinet Gorge Station Service
Business Case Justification Narrative Page 6 of 6
3.2 Provide and discuss the governance processes and people that will
provide oversight
Persons providing oversight include: Generation Electrical Engineering Manager, Generation Controls Engineering Manager, General Forman of Protection, Control and Meter technicians, Manager C&M - Electric Shop,
Cabinet Gorge Plant Manager, and Manager Engineering Protection
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
The persons identified in Section 3.2 will be called on to evaluate recommendations raised from the stakeholder group. Documented decisions
will be stored in the project folder located on the department network drive.
The undersigned acknowledge they have reviewed the Cabinet Gorge Station
Service and agree with the approach it presents. Significant changes to this will be coordinated with and approved by the undersigned or their designated representatives.
Signature: Date:
Print Name: Chris Clemens
Title: Cabinet Gorge Ops/Maint Manager
Role: Business Case Owner
Signature: Date:
Print Name: Alexis Alexander
Title: Director, GPSS
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Template Version: 05/28/2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 83 of 309
Cabinet Gorge Stoplogs
Business Case Justification Narrative Page 1 of 9
EXECUTIVE SUMMARY

Cabinet Gorge Spillgates are original to the project (early 1950’s vintage). The spillgates
are old and in need of replacement. Without a set of reliable stop logs we cannot
accomplish the spillgate work that is expected to take place over the next several years. Stop logs are used to isolate spillway gates from the reservoir for the Cabinet Gorge
Hydroelectric project. Each stop log assembly comprises nine individual stop log
elements or units, which when combined, will allow dewatering of one spillway gate. Each
stop log unit is predominantly a welded steel structure designed to fit inside stop log
guides embedded inside a large concrete structure, and to minimize water seepage by means of a rubber seal that is compressed under unit self-weight and hydrostatic forces.
Without these structures, we cannot efficiently and safely perform the upcoming spillgate
work.

Currently Cabinet Gorge spillgates are in need of repair due to missing rivets, bent
members, worn-out seals and heavy corrosion. It is worth mentioning that when the
condition assessment was performed at Cabinet Gorge, the Spillgates ranked poorly. If
those repairs are not made, we pose the risk of a spillgate being out of operational use
or a possible gate failure, which could result in an uncontrolled release of water. This would not be in the best interest of public safety, plant safety, and would negatively affect
our relationship with FERC, our main governing body and our customers at this facility.
The service code for this program is Electric Direct and the jurisdiction for the program is
Allocated North serving our electric customers in Washington and Idaho. Operating
Cabinet Gorge safely and reliably provides our customers with low cost, reliable power while ensuring the region has the resources it needs for the Bulk Electric System (BES).

Cabinet Gorge has operational flexibility and is operated to support energy supply,
peaking power, provide continuous and automatic adjustment of output to match the
changing system loads, and other types of services necessary to provide a stable electric grid, as well as to maximize value to Avista and its customers. The capacity of this plant
alone is 270 M.Th. estimated cost of the project is $1.2 Million. It is critical that this project
is completed prior to the completion of the planned Cabinet Gorge Spill gate upgrade
which is expected to be starting in 2025.
VERSION HISTORY
Version Author Description Date Notes
1.0 Andrew Burgess Updated Draft of original business
case. 7/6/2020 Budget and year
change
2.0 Chris Clemens Updated for the 2022-2026 SCRUM 7/6/2021 5-year Capitol
Planning Process
3.0 Chris Clemens Updated for the 2023-2027 SCRUM 8/23/2022 5-year Capitol
Planning Process

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 84 of 309
Cabinet Gorge Stoplogs
Business Case Justification Narrative Page 2 of 9
GENERAL INFORMATION

1. BUSINESS PROBLEM

1.1 What is the current or potential problem that is being addressed?
The Cabinet Gorge spillgates are nearly 70 years old and are in need of repair
due to missing rivets, bent members, worn out seals and heavy corrosion. To
do this needed spillgate work a functional set of Stoplogs must be designed and built prior to spillgate work commencing in 2025. These stoplogs would also help increase the safety factor of the spillway by giving the ability to stop water flow
should one of the old spillgates fail or get stuck in the open position. The
condition assessment performed in 2018 ranked the spillgates at Cabinet in
“poor condition”. A new set of stoplogs are needed to provide stability, reliability and safety of the aging spillway.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
The driver for this business case is Asset Condition. The stoplogs we have are
no longer functional and require major work to become of use. A new set of
stoplogs will support the spillgate work, which will provide stability and longevity
in the aging spillway into the future. Cabinet Gorge has operational flexibility and
is operated to support energy supply, peaking power, provide continuous and automatic adjustment of output to match changing loads, and other types of services necessary to provide a stable electric grid and to maximize value to
Avista and its customers.

Requested Spend Amount $1,200,000
Requested Spend Time Period 1 years
Requesting Organization/Department D07/GPSS
Business Case Owner | Sponsor Chris Clemens | Alexis Alexander
Sponsor Organization/Department A07/GPSS
Phase Initiation
Category Project
Driver Asset Condition
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 85 of 309
Cabinet Gorge Stoplogs
Business Case Justification Narrative Page 3 of 9
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
Currently, there is not a functional set of stoplogs at Cabinet. We cannot effectively begin spillgate work in 2025 until a functioning set is constructed. If we stick with the current plan and construct the stoplogs in 2023 we can perform
the much needed work to the spillgates and keep the current plan in motion. If
this is deferred it will prolong the work to the spillway gates and will put the plant
and spillway at risk.

1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the need listed above.
The stoplogs would be designed in a similar fashion as Noxon’s newly built
stoplogs. With the improved design they were able to achieve a better fit to the
slot, a tighter seal to mitigate leakage through the stoplog and a safer and more
efficient way to pick and set the stoplogs into place. Using the design and
construction criteria applied at Noxon for their stoplogs will help ensure that we end up with a set of stoplogs that function properly and provide a level of safety
for the expected spillgate work and at Cabinet Gorge.

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the
problem
A field study was performed on the current set of stoplogs by McMillen JACOBS
in 2017. The study showed that the current set of stoplogs is in “satisfactory” condition. The paint, seals and welds were noted as needing to be addressed.
However, these are the original stoplogs and it may be hard to get an engineer
to sign off on these as ever being deemed safe to use. The study showed that
refurbishment of the existing could be accomplished but the O&M cost estimated
to be 700-800k to refurbish would be more than half the cost of a complete new set. The old set have never been placed in service, so there is some risk
involved in refurbishing.

1.5.2 For asset replacement, include graphical or narrative representation of metrics associated with the current condition of the asset that is proposed for replacement.
The metric supporting the replacement of the current stoplogs is that they are
no longer functional or useful. The original stoplogs in their current state are not
feasible or safe to use. Estimated cost to refurbish the existing set is 700-800k.
While the Cabinet Gorge stoplogs appear to be in good shape (no damaged/bent members, minimal rust, negligible section loss), Engineering cannot locate the original design. Without the original design, we are unable to
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 86 of 309
Cabinet Gorge Stoplogs
Business Case Justification Narrative Page 4 of 9
demonstrate that these stoplogs are safe to work behind. A new engineering
calculation would be required to verify the adequacy of the existing stoplogs but
could also identify the need for significant structural modification. Additionally, the last time the stoplogs were coated was in 1988. The coating is now 34 years old and should be replaced. Unfortunately, the work performed in 1988 appears
to have been spot blasting and spot painting, nearly guaranteeing that lead
based paint from original construction is still present on the stoplogs. As a result
of the necessary abatement, a new paint system will be far more costly.

Option Capital Cost Start Complete
Replace with new Stoplogs $1,200,000 01 2023 12 2023
Refurbish existing set (O&M) $800,000 01 2023 12 2023

2.1 Describe what metrics, data, analysis or information was considered when preparing this capital request.
A field study was performed on the current set of stoplogs by McMillen JACOBS
in 2017. The study showed that the current set of stoplogs is in “satisfactory”
condition. The paint, seals and welds were noted as needing to be addressed.
However, these are the original stoplogs and it may be hard to get an engineer
to sign off on these as ever being deemed safe to use. The study showed that refurbishment of the existing could be accomplished but the O&M cost estimated to be 700-800k to refurbish would be more than half the cost of a complete new
set. The old set have never been placed in service, so there is some risk
involved in refurbishing. New stoplog design would be similar to the Noxon set
that was built in 2018. Major spillgate work in 2024 will require a well-designed functional set of stoplogs to complete the work safely.

2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include any known or estimated reductions to O&M as a result of this investment.
The capital cost of $1,200,000 will be spent in 2023. In first quarter
design/engineering will take place. Second quarter material will be purchased,
and fabrication will begin. Third quarter fabrication complete. Fourth quarter
delivery/commissioning of the stoplogs. There is significant risk involved with not procuring a set of stoplogs prior to the spillgate work scheduled for 2024.
The original 1950’s vintage spillgates have exceeded their expected life cycle
and need replacement.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 87 of 309
Cabinet Gorge Stoplogs
Business Case Justification Narrative Page 5 of 9
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
The timing and execution of this project will enable the needed upgrade of the Cabinet Gorge Spillgate project to proceed in 2024. The spillgates at Cabinet Gorge are original to the project and are at the end of their useful life. With
Noxon and Cabinet preparing to officially enter the EIM in April 2022 it is
expected that we will Operate and cycle the spillgates even more once we enter
the market. Failure of a spillgate would impose significant operational impacts to the plant, power schedulers, and public by limiting our ability to control the flow of water safely and efficiently through the dam.

2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
The repair of the existing set of stoplogs was considered but due to the high cost to refurbish and the outdated design of the old stop logs, this is not the most
reliable and safest option.

While the Cabinet Gorge stoplogs appear to be in good shape (no damaged/bent members, minimal rust, negligible section loss), Engineering cannot locate the original design. Without the original design, we are unable to
demonstrate that these stoplogs are safe to work behind. A new engineering
calculation would be required to verify the adequacy of the existing stoplogs but
could also identify the need for significant structural modification. Additionally, the last time the stoplogs were coated was in 1988. The coating is now 34 years old and should be replaced. Unfortunately, the work performed in 1988 appears
to have been spot blasting and spot painting, nearly guaranteeing that lead
based paint from original construction is still present on the stoplogs. As a result
of the necessary abatement, a new paint system will be far more costly.

The original lifting beam that was used with the Cabinet Gorge stoplogs was
also shared with Noxon Rapids. During the recent project to replace the Noxon
Rapids stoplogs, the lifting beam was evaluated. This evaluation determined
that the beam no longer met standards for below the hook lifting devices. As
such, the lifting beam was destroyed along with the old Noxon Rapids stoplogs. To utilize the existing Cabinet Gorge stoplogs, we will need to procure
a new lifting beam.

Engineering has determined that the costs associated with procuring a new
lifting beam and re-analyzing the stoplog system exceed the value of the existing stoplogs. The risk and cost associated with attempting to use the existing
stoplog system are far greater than I originally anticipated.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 88 of 309
Cabinet Gorge Stoplogs
Business Case Justification Narrative Page 6 of 9
Procuring a new stoplog system will ensure the stoplogs meet all current design
criteria and are safe for our crews to work behind. All coatings, seals and rollers
will be new and adequate for a service life well beyond the upcoming Spillway Gate Replacement project. Additionally, we can utilize the new stoplog lifting beam from Noxon Rapids Dam in both locations at a cost savings to the
utility. Knight Construction has recently completed a nearly identical stoplog
project for Avista at Noxon Rapids and we have a high degree of faith in their
abilities and workmanship. Anticipated costs associated with a new stoplog system are high, but ensure a modern, high-quality system with fewer unknowns that could drive up costs further into the project.
The most feasible and safest option is to design and build a new set of stoplogs
for the anticipated spillgate work in 2025.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 89 of 309
Cabinet Gorge Stoplogs
Business Case Justification Narrative Page 7 of 9

2.5 Include a timeline of when this work will be started and completed. Describe when the investments become used and useful to the customer. spend, and transfers to plant by year.
In first quarter design/engineering will take place. Second quarter material will
be purchased, and fabrication will begin. Third quarter fabrication complete.
Fourth quarter delivery/commissioning of the stoplogs. Transfer to plant will
occur at the end of the first year once commissioning is complete.

2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Cabinet Gorge affordably supports the power needs of our company and our
customers. By taking care of this plant we support our mission of improving our
customer’s lives through innovative energy solutions which includes hydroelectric generation. By executing this project, we ensure that Cabinet
Gorge is performing at a high level and serving our customers with affordable
and reliable energy.

2.7 Include why the requested amount above is considered a prudent investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
Industrial Stoplogs of this size and weight fall into this range of cost. The overall length and width of the stop logs are similar to the set that was built in 2018 for the upcoming Noxon spillgate project. We used the dollar figure spent on
Noxon’s stoplogs to determine the overall project cost at Cabinet.
A formal Project Manager will be assigned to a project of this size. The project
will be managed within project management practices adopted by the Generation Production and Substation Support (GPSS) department. This includes the creation of a Steering Committee and a formal Project Team. Once
the project is initiated, reporting on scope, schedule and cost will occur monthly.
Changes in scope, schedule, or cost will be surfaced by the Project Manager to
the Steering Committee for governance. The Project Manager will manage the
project through its conclusion.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 90 of 309
Cabinet Gorge Stoplogs
Business Case Justification Narrative Page 8 of 9
2.8 Supplemental Information

2.8.1 Identify Customers and Stakeholders that identify with the Business Case.
The primary stakeholders for this project are, the Hydro Regional Manager
at Cabinet Gorge, Cabinet Gorge Plant personnel, GPSS Engineering,
GPSS Construction and Maintenance, Power Supply, Environmental Resources. Other stakeholders may be identified during project initiation.

2.8.2 Identify any related Business Cases
This project will need to be completed prior to the spillgate project expected to start in 2025. The stoplogs will need to be designed built and
commissioned prior to any major spillgate work at Cabinet Gorge.

3.1 Steering Committee or Advisory Group Information
A formal Project Manager will be assigned to this project. The project will be
managed within project management practices adopted by the Generation
Production and Substation (GPSS) Department. A Steering Committee will be
formed for this project. The Project Manager will manage the project through its conclusion.

3.2 Provide and discuss the governance processes and people that will
provide oversight
Management of this project will include the creation of a steering committee which will include mangers representing the key stakeholders involved in this
project. The Project will also be executed by a formal Project Team lead by the
Project Manager.
3.3 How will decision-making, prioritization, and change requests be documented and monitored
Once the project is initiated, reporting on scope, schedule and cost will occur
monthly. Changes in scope, schedule, or cost will be surfaced by the Project
Manager to the Steering Committee for governance.
The undersigned acknowledge they have reviewed the Cabinet Gorge Stoplogs and agree with the approach it presents. Significant changes to this will be coordinated with and approved by the undersigned or their designated representatives.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 91 of 309
Cabinet Gorge Stoplogs
Business Case Justification Narrative Page 9 of 9

Signature: Date:
Print Name: Chris Clemens
Title: Cabinet Gorge Plant Manager
Role: Business Case Owner

Signature: Date:
Print Name: Alexis Alexander
Title: Director GPSS
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
9/8/2022
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 92 of 309
Cabinet Gorge Unit 1 Governor Upgrade
Business Case Justification Narrative Page 1 of 6

EXECUTIVE SUMMARY

Governors for Cabinet Gorge Units 2, 3 and 4 are all being upgraded to an open platform
Programable Logic Controller (PLC) based control system. The current governor controller
on Unit 1 is a GE Mark VIe that is not an open platform control system. Open platform control systems allow for in-house modifications as opposed to bringing in the manufacturer for each
settings change. The recommended solution is to upgrade the Unit 1 governor controller to
the same open platform PLC based control system to be consistent with the other three units at Cabinet Gorge as well as other units across both the Spokane River. The cost of the solution is approximately $600,000. Consistency across all governor equipment platforms
reduces the response time for the relay technicians, electricians and mechanics in cases of troubleshooting and during forced outages. This also reduces response time by eliminating
dependency on outside vendors, thus reducing outage duration and improving unit and
overall plant reliability and availability. The risks of not approving this business case continues reliance on outside vendors that historically required longer response times and
extended outage times, as such a large portion of the control system is considered
proprietary and is locked down requiring the outside vendor technical service representative to travel to the plant and be onsite to troubleshoot and/or make settings changes locally.

VERSION HISTORY
Version Author Description Date Notes
1.0 Kristina Newhouse Initial draft to convert to new template 7/2/2020 Existing Business Case.
Executive summary only
2.0 Kristina Newhouse Complete remaining template 7/31/2020 Remaining sections 1, 2, & 3.
3.0 Chris Clemens Updated for SCRUM 5-Year Plan 8/23/2022 Changed dates from 2024 to 2023

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 93 of 309
Cabinet Gorge Unit 1 Governor Upgrade
Business Case Justification Narrative Page 2 of 6

GENERAL INFORMATION

Requested Spend Amount $600,000
Requested Spend Time Period 1 year
Requesting Organization/Department Generation Production and Substation Support
Business Case Owner | Sponsor Chris Clemens | Alexis Alexander
Sponsor Organization/Department Generation Production and Substation Support
Phase Initiation
Category Project
Driver Asset Condition

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
This business case is addressing inconsistency across governor controllers at Cabinet Gorge HED. Governors for Units 2, 3 and 4 are being upgraded to an open platform
PLC based control system. The current governor controller on Unit 1is a GE Mark VIe and is not an open platform control system. Unit 1 governor is proposed to be upgraded to the same open platform PLC based control system to be consistent with Units 2, 3
and 4
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
The major driver of this business case is Asset Condition. Upgrading the Unit 1 governor controller to the same open platform PLC based control system to be
consistent with other units at Cabinet Gorge as well as other units across both the Spokane River would reduce the response time for the relay technicians, electricians
and mechanics in cases of trouble shooting and during forced outages.
1.3 Identify why this work is needed now and what risks there are if not approved or is deferred
This work is needed now, following the last unit upgrade at Cabinet Gorge HED. The
existing Unit 1 governor controller is a GE Mark VIe and is typically found in thermal units. Troubleshooting and modifying the GE Mark VIe program is limited and has often
required GE’s assistance. These issues were a driver in the decision to not upgrade
Units 2-4 to GE Mark VIe governors but rather move toward the standard governor used on the Spokane River. Doing the work now takes advantage of engineers,
technicians and operations efforts to continue focusing on improvements at Cabinet
Gorge HED.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 94 of 309
Cabinet Gorge Unit 1 Governor Upgrade
Business Case Justification Narrative Page 3 of 6

1.4 Identify any measures that can be used to determine whether the investment would successfully deliver on the objectives and address the
need listed above.
Maintaining and operating equipment that is standardized and consistent throughout a
generating facility and across multiple generating facilities improves cross training amongst engineering, technicians, and operations. It also improves response time
when making planned changes or troubleshooting issues. This response time can be measured.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
The Controls Engineering Memo from 6/2/2017 with the subject “Standard Governor
Control System” is found in the business case folder on SharePoint.
2. PROPOSAL AND RECOMMENDED SOLUTION

Option Capital Cost Start Complete
[Recommended Solution] Upgrade Unit 1 Governor
Controler
$600k 1 2023 12 2023
[Alternative #1] Do Nothing $0
The recommended solution is to upgrade the governor controller to the standard, an
open platform PLC based equipment package which is being implemented across both the Spokane River and Clark Fork River Projects. Consistency and familiarity with this common standard equipment platform allows for quick and efficient troubleshooting by
local plant crews during both planned and forced outages resulting in improved reliability and availability. This option will also eliminate our dependency on outside vendors for governor system repairs and settings changes, thus reducing O&M costs
and improving unit and overall plant reliability and availability.
2.1 Describe what metrics, data, analysis or information was considered when preparing this capital request.
The controls Engineering Memo from 6/2/2017 with the subject “Standard Governor
Control System” was considered when preparing this capital request. The memo explains the evaluation that took place when standardizing the governor control
system for future governor upgrades.
2.2 Discuss how the requested capital cost amount will be spent in the current year (or future years if a multi-year or ongoing initiative). Include any
known or estimated reductions to O&M as a result of this investment.
The requested amount for this project is based on an existing contract with L&S (R-
41566) for the governor replacement for all four Units at Cabinet Gorge. The requested capital costs will cover design, material, factory acceptance testing, installation, and
commissioning.
The benefit of upgrading from a proprietary governor controller to a more common standardized one is that operators and technicians are trained and familiar across
multiple generating facilities and there are many third parties with expertise capable of providing support all of which reduce O&M.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 95 of 309
Cabinet Gorge Unit 1 Governor Upgrade
Business Case Justification Narrative Page 4 of 6

2.3 Outline any business functions and processes that may be impacted (and how) by the business case for it to be successfully implemented.
Resources will need to be allocated by each stakeholder listed in 2.8.1 for the project
to be carried out from initiation to completion.
This project will benefit Power Supply and System Operations as they are responsible for dispatching power from Cabinet Gorge plant to meet contractual obligations and
managing the day-to-day transmission system operational requirements. It will also benefit engineering and the shops as they are responsible for providing maintenance and support with the generating facilities.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
The only alternative would be to do nothing. This option would not allow for conversion to the open platform PLC and associated mechanical, electrical and control equipment
upgrade, and would not provide for long term reliability and availability improvements nor would it reduce our long-term O&M cost. The major risk associated with keeping
the existing governor is our continued dependency on outside vendors for repairs and
settings changes.
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
spend, and transfers to plant by year.
The initiation of this work is dependent on the completion of the Cabinet Gorge Unit 4 Control Upgrade. The design for this project will be similar to the three other
governor designs at Cabinet Gorge. A contract is already in place with vendor that
manufactures the governor that is Avista standard governor. The actual unit outage would likely occur during the late summer through fall for a duration of
approximately two months. The investment will be transferred to plant at the
completion of the full project.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
By proactively replacing non standardized and inconsistent assets we are able to increase reliability within our generating facilities. This program safely, responsibly, and
affordably improves our customers’ lives through innovative energy solutions.
2.7 Include why the requested amount above is considered a prudent investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
There have been many upgrades at Cabinet Gorge HED including upgrading three of the four governors to a standard governor system. It is important to complete the work
at Cabinet Gorge HED by changing out the proprietary forth governor controller on Unit
1. Unit 1 is a Black Start Unit, reliability and availability of this unit is critical to the transmission system restoration plan. The governor controller is a single point of failure.
With Unit 1 governor controller upgraded to the standard governor controller it allows
operators, technicians, and engineers to maintain and troubleshoot with more familiarity in the case of an issue. If the existing standard governor controller on any
of Avista’s seven other hydro units proves to be problematic this project will be re-
evaluated.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 96 of 309
Cabinet Gorge Unit 1 Governor Upgrade
Business Case Justification Narrative Page 5 of 6

2.8 Supplemental Information 2.8.1 Identify customers and stakeholders that interface with the business case
The following stakeholders will interface with this business case:
• Controls Engineering
• Mechanical Engineering
• Project Management
• PCM Shop
• Electric Shop
• Mechanic Shop
• Hydro Operations
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 97 of 309
Cabinet Gorge Unit 1 Governor Upgrade
Business Case Justification Narrative Page 6 of 6

3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
The project with have a project manager and steering committee for ongoing vetting.
The steering committee will minimally consist of the Controls Engineering Manager,
the Protection Control Meter Technician Foreman, and the Cabinet Gorge Plant Operations Manager.
3.2 Provide and discuss the governance processes and people that will
provide oversight
More detailed project governance protocols will be established during the project chartering process. The Steering Committee will allocate appropriate resources to all
project activities once the scope is better defined. 3.3 How will decision-making, prioritization, and change requests be documented and monitored
Project decisions will be coordinated by the project manager. The Steering
Committee will be advised when necessary. Regular updates will be provided to the Steering Committee by the project manager as project scope, schedule and budget are defined, and through the course of the project execution.
4. APPROVAL AND AUTHORIZATION

The undersigned acknowledge they have reviewed the Cabinet Gorge Unit 1 Governor Upgrade and agree with the approach it presents. Significant changes to this will be coordinated with and approved by the undersigned or their designated representatives.

Signature: Date:
Print Name: Chris Clemens
Title: Cabinet Gorge Plant Manager
Role: Business Case Owner

Signature: Date:
Print Name: Alexis Alexander
Title: Director GPSS
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 98 of 309
Cabinet Gorge Unwatering Pump Upgrade
Business Case Justification Narrative Template Version: 08/04/2020 Page 1 of 6
EXECUTIVE SUMMARY

Cabinet Gorge Hydroelectric Development (HED) is the second largest generating plant in Avista’s
hydropower fleet. It is located on the Clark Fork River in Bonner County, Idaho. With four
generators, it has a 270 MW output capacity. Built in 1952, the plant has retained most of its
original equipment which is now aging and at end of life. This plant was designed for base load
operation, but today is called on to not only provide load but to quickly change output in response
to the variability of wind generation, to changing customer loads and other regulating services
needed to balance the system load requirement and assure transmission system reliability.

In order to respond to these new demands, it is necessary to upgrade many of the plant’s original
systems. One of those critical systems are the unwatering pumps. The unwatering system at Cabinet
Gorge consist of two unwatering sumps, each housing three pumps, one 50HP and two 200HP pumps.
The 50HP (1,000 GPM) pumps are used to pump out water from normal plant leakage. The 200HP
(5,000 GPM) pumps are used to drain out generating units when performing routine maintenance.
The pumps, original to the plant, are progressively requiring increasing maintenance. Replacing all
six pumps with new pumps at a cost of $800,000 is recommended. Timing for this work is related to
Avista’s entrance into the Energy Imbalance Market (EIM). The risks for not completing these
upgrades include an inability to perform critical maintenance, potentially flooding the plant, and
thereby jeopardizing Avista’s ability to serve its customers.

VERSION HISTORY
Version Author Description Date Notes
Draft Chris Clemens Initial draft of original business case 10/25/2020
1.0 Chris Clemens Updated for Budget Year 2023 8/23/2022

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 99 of 309
Cabinet Gorge Unwatering Pump Upgrade
Business Case Justification Narrative Template Version: 08/04/2020 Page 2 of 6
GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
The problems being addressed are the plant unwatering pumps at Cabinet Gorge. These
pumps have reached the end of their life to provide reliable plant dewatering.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer.
The current plant unwatering pumps were installed during the original plant construction
in the early 1950’s. These pumps can no longer be maintained, due to the manufacturer
not supporting the equipment. Customers will be benefited through higher reliability of
new pumps: i.e. reduced downtime during maintenance evolutions and manufacturer
support of the replaced equipment. Also, the original pumps were designed with an oil
lubricating system that has the potential to get oil into the river while the pumps are in
operation. The new pumps will have a water lubricating system that will meet current
environmental requirements.

Requested Spend Amount $800,000
Requested Spend Time Period 2 years
Requesting Organization/Department D07/GPSS
Business Case Owner | Sponsor Chris Clemens | Alexis Alexander
Sponsor Organization/Department A07/GPSS
Phase Execution
Category Project
Driver Asset Condition
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 100 of 309
Cabinet Gorge Unwatering Pump Upgrade
Business Case Justification Narrative Template Version: 08/04/2020 Page 3 of 6
1.3 Identify why this work is needed now and what risks there are if not approved or is deferred
The pumps have reached the end of their service life. They are a critical plant system and
without their reliable operation, the plant could easily flood and/or limit the ability to
perform unit maintenance. As we go into the EIM market, unit maintenance outages will
be scheduled one year in advance and schedule adherence is crucial to plant operation. If
these pumps fail, we could jeopardize the maintenance schedule and forgo much needed
preventative maintenance activities. In addition, in the case of a failure, the replacement
parts or new pumps would have to be manufactured, increasing the length of the
downtime. The current systems are not environmentally-friendly so there is a risk in
continually polluting our rivers with these outdated oil lubricated pumps.

1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
By replacing the current pumps with new pumps, we will provide consistency with industry
standards. These upgrades will improve the plant’s overall reliability. This will also reduce
current maintenance costs and provide many years of efficient, reliable and
environmentally-sound plant dewatering operations.

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
No studies have been performed.
1.5.2 For asset replacement, include graphical or narrative representation of metrics associated with the current condition of the asset that is proposed for
replacement.
2. PROPOSAL AND RECOMMENDED SOLUTION

Option Capital Cost Start Complete
Replace all six pumps and check valves over a two-
year period.
$800,000 01 2022 12 2023

2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Capital planning consists of bids from manufacturers to determine the best cost and
schedule. Engineering and vendors have been consulted to determine industry best
practices and to determine installation costs and schedules
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 101 of 309
Cabinet Gorge Unwatering Pump Upgrade
Business Case Justification Narrative Template Version: 08/04/2020 Page 4 of 6

2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
Installations and commissioning of purchased equipment will take place in 2022.
Maintenance costs will be reduced because the current pumps require ongoing
maintenance. In 2019, Unwatering pump #1 was removed from service because of high
vibration and the motor was pulling 60 amps over the nameplate rating. The mechanical
crew spent 2 weeks removing the motor and sending it in to be cleaned, baked and dipped.
Then the bearings were replaced, and the motor was reinstalled. Neither problem
(vibration nor high amperage) was resolved. The cost to perform this maintenance was
$50,000. Due to the age of these original pumps, it is difficult to get parts. Similarly, it is
not sustainable to fix the vibration issues because the pumps and motors have been
modified through the years to keep them in service. It is believed that replacing the pumps
will be more cost effective than trying to maintain the current pumps. Reliability will be
improved because the new pumps will be maintenance-free for many years.

2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
The successful upgrade of the system will allow the plant to operate more reliably during
the future.

2.4 Discuss the alternatives that were considered and any tangible risks and mitigation strategies for each alternative.
There is an alternative in only replacing four of the six pumps. The smaller pumps have had
the motors replaced 20 years ago, but the pump itself was not overhauled. The larger
pumps, if replaced, could act as a backup if the smaller pump was to fail. Though the
smaller pumps would still be utilizing the oil lubricating system. They still should be
replaced in the future to meet environmental standards.

2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
This project would take place over a two-year period. We will procure and install all six
pumps within that timeframe. The work would take 1 week per pump, totaling six weeks.
We would purchase three pumps in January 2022 and start the installation in September
of 2022. Then purchase the additional three pumps in January 2023 and start the
installation in September of 2023. There would be no outages or generation lost during
these upgrades. We will be able to replace one pump at a time, keeping the plant
unwatering sumps in service.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 102 of 309
Cabinet Gorge Unwatering Pump Upgrade
Business Case Justification Narrative Template Version: 08/04/2020 Page 5 of 6
2.6 Discuss how the proposed investment aligns with strategic vision, goals, objectives and mission statement of the organization.
Upgrading the plant unwatering pumps at Cabinet Gorge contributes to the safe and
responsible design, construction, operation and maintenance of Avista’s generating fleet.

2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In addition, please explain how the investment prudency will be reviewed and re-evaluated throughout the project
We ranked this project based on a ranking matrix to ensure prudent consideration of cost,
scheduling and personnel resources. These six pumps are ranked in poor condition. There
are only a few assets within the Hydro Department with a poor rating. This shows the need
and urgency to replace these pumps.

2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
The Mechanical shop, Electric shop, Engineering, Operations, Environmental, and Project
Management are required.

2.8.2 Identify any related Business Cases
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
The Steering Committee consists of the following members: Plant Manager, Chief
Operator, Station Mechanic and Station Electrician.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 103 of 309
Cabinet Gorge Unwatering Pump Upgrade
Business Case Justification Narrative Template Version: 08/04/2020 Page 6 of 6
3.2 Provide and discuss the governance processes and people that will provide oversight
Persons providing oversight include: Generation Mechanical Engineer, Mechanical Shop
Forman and Station Mechanic.

3.3 How will decision-making, prioritization, and change requests be
documented and monitored
The persons identified in Section 3.2 will be called on to evaluate recommendations raised
from the Stakeholder Group. Documented decisions will be stored in the project folder
located on the department network drive.
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Cabinet Gorge Unwatering Pump
Upgrade and agree with the approach it presents. Significant changes to this will be
coordinated with and approved by the undersigned or their designated representatives.

Signature: Date:
Print Name: Chris Clemens
Title: Cabinet Gorge Plant Manager
Role: Business Case Owner

Signature: Date:
Print Name: Alexis Alexander
Title: Director GPSS
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 104 of 309
Generation DC Supplied System Update
Business Case Justification Narrative Template Version: 04.21.2022 Page 1 of 7
EXECUTIVE SUMMARY
The Generation DC Supplied System program covers all the generation and control facilities. It is
the backbone for supplying power to the protective relays, breakers, controls and communication systems. Experience shows that we must continually monitor, review and maintain our DC
system. To maintain reliability, we follow NERC requirements and design enhancements for the DC system to be monitored and tested. The equipment manufactures provide estimated life span for batteries and auxiliary equipment. Some of these estimates have not been accurate and
change outs early due to failing tests or issues with the equipment have been necessary. Proven manufactures are used to improve reliability and life. The cost of this program overtime is approximately $420,000 a year.
The overall benefit to customers would be the reliability of our generation and control facilities. This risk of not approving this business case would result in maintenance work ballooning into
large projects as there would be no prepared design to address issues when problems arise.
Waiting for issues to arise can extend outages and leave the plant exposed for extended time frames for repairs and/or replacement parts. Upon failure we would temporarily restore the system
back to working condition with the knowledge that we have to address it later. It places plant
equipment at risk if a key element of the DC system were to fail, particularly the battery system. It also does not provide a means to perform required NERC testing and does not provide a means
to plan for cost efficient replacements. Also, critical AC loads served from the Uninterruptible
Power Supply, UPS have increased to the point where we can no longer get a UPS that is of necessary size. We would have to install more UPS systems, creating more maintenance work
and increasing the NERC testing requirements. It also does not address any other issues that
our design standard is intending to address. While it is a much higher life cycle cost and
operationally impactful option. The recommended solution was reviewed by GPSS Engineering and approved by GPSS Management.

VERSION HISTORY
Version Author Description Date Notes
1.0 Glen Farmer Initial Version 4/10/2017
2.0 Glen Farmer Updated timeline from 5-year plan 8/1/2020
3.0 Kristina Newhouse Updated to 2022 Template 8/15/2022

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 105 of 309
Generation DC Supplied System Update
Business Case Justification Narrative Template Version: 04.21.2022 Page 2 of 7
GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
Traditionally, the Direct Current (DC) system, (aka Battery System) at each generation plant is used for protection and monitoring of the plant. All the protection
relays, breaker control circuits and monitoring circuits are fed from this source. The source is assumed to always be on-line and able to supply the critical load for a predetermined length of time.
As technology has evolved, other standalone DC systems that were installed at different times. Typical plants now have standalone DC Systems for: general station,
Uninterruptible Power Supplies (UPS), governors (electronic turbine speed
controllers), communications and control systems. Each of these systems have a battery bank, battery charger, converters to supply different voltages, and distribution
panels and circuits. As things have changed on the generating units or in the balance
of plant systems, the DC load requirement has significantly increased and the time duration for the systems to supply this critical load has increased. Our current practice
is to replace the battery banks per manufactures life cycle recommendations. This
practice is not addressing the additional load added to the systems.
Some of the other issues we have had on the DC systems are the failing of battery
cells due to inconsistent temperature and environmental control needed to maintain these present battery systems. The system life cycle is 20 years at its normal operating temperature of 77 degrees F. For temperatures fifteen degrees F over the
normal operating temperature the life cycle is decreased by 50 percent. Component failure, utilization from multiple extended outages and manufactures quality are other problems we have experienced on these systems.
Finally, there are compliance requirements from the North American Electric Reliability Corporation (NERC) for inspections, maintenance and testing of the battery banks to make sure they are in good working order and will perform when called upon.
To perform these inspections and maintenance, and testing needs, it requires either unit or plant outages to comply with the requirements for multiple DC systems that
are now present in our stations.
To address these multiple issues, a new Generation Plant DC Standard was developed by the engineering group. The new Generation Plant DC Standard System
Requested Spend Amount $420,000
Requested Spend Time Period 10 years
Requesting Organization/Department GPSS
Business Case Owner | Sponsor Kristina Newhouse | Alexis Alexander
Sponsor Organization/Department GPSS
Phase Execution
Category Program
Driver Asset Condition
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 106 of 309
Generation DC Supplied System Update
Business Case Justification Narrative Template Version: 04.21.2022 Page 3 of 7
provides for layers of back up and redundancy to address current and future capacity needs as well as addressing maintenance and testing requirements. This Program
will replace existing DC systems at Avista’s owned and operated generation plants
with a system that meets this new design standard. The Generation Plant DC Standard will be used as a guide for defining the base scope of the project.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
The activity objectives are to order the plant replacements in a timeline that will allow for stages of a project to happen and use our engineering and construction staffing. At each plant the DC System will be updated to meet the current Generation Plant DC
System Standard and the following:
• Comply with NERC requirements for inspection and testing.
• Address battery room environmental conditions to optimize battery life.
• Replace any legacy UPS systems with an invertor system.
• Address auxiliary equipment based on life cycle.
• Hydrogen sensing and fire alarm, eyewash station and lighting.
• Wall separation of batteries and auxiliary equipment.
• Install Programmable logic controller monitoring and new operating
screens to provide visibility for operations and maintenance purposes.
• Provide new distribution panels, disconnect switches, voltage conversion
devices for communications equipment that operate at different voltages.
• Establish current drawings, construction documents, I/O list, plans, schedules, manuals and as-builts.
1.3 Identify why this work is needed now and what risks there are if not approved or
is deferred
The biggest risk is a battery bank not being able to provide load to the plant. The batteries are supposed to have a 20-year life based on the manufacture, but we have
only seen one manufacture perform to this level. We are using this manufacture going forward and expect to have them last the full life.
If not approved and we have a failure of a battery then budgets, schedules and
resources on other projects would be diverted to handle fixing the failure.
1.4 Identify any measures that can be used to determine whether the investment
would successfully deliver on the objectives and address the need listed above.
With the DC design standard, we are creating the best possible environment for the battery banks and have enhanced monitoring of the system. This gives Operations
better insight to how the DC system is functioning.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
The preparation of our DC Standard incorporates IEEE design parameters and standards. It has redundancy built in for testing and suppling load.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 107 of 309
Generation DC Supplied System Update
Business Case Justification Narrative Template Version: 04.21.2022 Page 4 of 7
1.5.2 For asset replacement, include graphical or narrative representation of metrics associated with the current condition of the asset that is proposed for
replacement.
2. PROPOSAL AND RECOMMENDED SOLUTION
The recommended solution is to construct new systems as part of a programmatic effort. This would allow for prioritized and planned series of projects to upgrade the existing station
DC systems to the Generation Plant DC Standard. This will save time and expense over the life cycle of the station with the flexibility it provides to address future capacity and
maintenance needs, and the ability to perform NERC required testing. It also has the benefit
allowing a schedule to be established for both the engineering and the installation. Both of these resources are constrained and it would allow options of contracting or in-house
consideration. A typical schedule to execute is given below. Each planned project would take
approximately 16 to 18 months. Added complexity, cost, and time may be needed if extensive work is required to address the temperature and other environmental issues with the location
of the new battery system. This program aligns with Avista’s Safe and Reliable Infrastructure
goal through investment to achieve optimum life-cycle performance and operational safety. In addition, it helps Avista meet its corporate compliance goals.
Alternative 1 is to address the DC system as part of another capital project. In this case the scope of the DC system upgrade project is often a lower-level effort and is subordinated to the primary project. The table below shows the current upgrade plans. While planning and
scoping management can manage the concerns about making sure the DC Supplied Systems can be fully addressed, we do not have plans to work through all the plants. This would leave the program incomplete.
Alternative 2 to replace parts as they fail doesn’t address any of the requirements for Standards, NERC inspection and testing, or the room itself. The parts fail at different time and we are subject to more outages. This also requires reaction to a critical system failure.
Clearly replacing failed parts and components is a more costly item than performing planned work and without a planned effort, deployment of that new Generation Plant DC Standard
would likely take decades. Replacing as components fail and gradually build out to our
standard has the benefit of minimizing the costs of this program. However, it would be unpredictable would make labor planning impossible. This would also place the plant at a
higher likelihood of forced outages and equipment damages if we wait for failure.

Option Capital Cost Start Complete
[Recommended Solution] Establish independent DC
system replacement program to bring plants to
standard as quickly as possible
$1.315M 01 2017 08 2026
[Alternative #1] Address the DC system standards
as we are doing other system or unit upgrades.
$1.315M 015 2017 08 2030
[Alternative #2] Address the DC systems as they fail
testing or battery issues arise with the goal of
making it like our standard over time.
$1.315M 01 2017 12 2037
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
The capital request was developed from budgetary quotes from manufacture and compared to previous projects of similar type.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 108 of 309
Generation DC Supplied System Update
Business Case Justification Narrative Template Version: 04.21.2022 Page 5 of 7
2.2 Discuss how the requested capital cost amount will be spent in the current year (or future years if a multi-year or ongoing initiative). (i.e., what are the expected functions,
processes or deliverables that will result from the capital spend?). Include any known or
estimated reductions to O&M as a result of this investment.
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy
Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]
There are normally three different projects happing each year. One project would be in
the initiation phase, the next would be in the execution phase and the next would be in the close out phase. Maintenance is reduced after the execution phase and we have
not seen it pick back up for the first five years of the life span.
2.3 Outline any business functions and processes that may be impacted (and how) by the business case for it to be successfully implemented.
The engineer business process would be used. This allows for the stakeholders to be
involved from the beginning to the end of the project.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
The risk of addressing the DC system when there is an issue is usually that is too late. We have had one instance where the DC system failed and some equipment was
damaged due to this not functioning correctly.
2.5 Include a timeline of when this work will be started and completed. Describe
when the investments become used and useful to the customer.
We normally have one project per year become used and useful.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
A new DC System contributes to the Safe and responsible design, construction,
operation and maintenance of Avista’s generation fleet.
2.7 Include why the requested amount above is considered a prudent investment, providing or attaching any supporting documentation. In addition, please explain how the investment prudency will be reviewed and re-evaluated throughout the project
We ranked this project based on a ranking matrix to ensure prudent consideration of
costs, scheduling and personnel resources.
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
• Electric shop
• PCM shop
• Electrical Engineering
• Controls Engineering
• Hydro Operations
• Thermal Operations
• Protection Engineering
• Environmental
• Project Management
• Power Supply

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 109 of 309
Generation DC Supplied System Update
Business Case Justification Narrative Template Version: 04.21.2022 Page 6 of 7
2.8.2 Identify any related Business Cases
None.
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
The Steering Committee consists of the following members: Manager of Project Delivery, Manager of Maintenance and Construction, Manager of Hydro Operations
& Maintenance, and Manager of Thermal Operations & Maintenance.
3.2 Provide and discuss the governance processes and people that will provide oversight
More detailed project governance protocols will be established during the project
chartering process. The Steering Committee will allocate appropriate resources to all project activities once the scope is better defined.
Persons providing oversight include: Generation Electrical Engineering Manager, Forman PCM shop, Manager C&M - Electric Shop and the Plant Managers.
3.3 How will decision-making, prioritization, and change requests be documented
and monitored
Project decisions will be coordinated by the project manager. The Steering
Committee will be advised when necessary. Regular updates will be provided to
the Steering Committee by the project manager as project scope, schedule and budget are defined, and through the course of the project execution.
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the DC Supplied System Upgrades
business case and agree with the approach it presents. Significant changes to this will be coordinated with and approved by the undersigned or their designated representatives.

Signature: Date: 8/15/2022
Print Name: Kristina Newhouse
Title: Controls/Electrical Eng Manager
Role: Business Case Owner

Signature: Date:
Print Name:
Title:
Role: Business Case Sponsor

Signature: Date:
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 110 of 309
Generation DC Supplied System Update
Business Case Justification Narrative Template Version: 04.21.2022 Page 7 of 7
Print Name:
Title:
Role: Steering/Advisory Committee Review

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 111 of 309
HMI Control Software
Business Case Justification Narrative Template Version: 04.21.2022 Page 1 of 8
EXECUTIVE SUMMARY
The existing Human Machine Interface (HMI) software, Wonderware reached it’s end of life as support
ended in 2017. HMI Control Software is used to develop control screens and to operate and monitor generating systems within Avista Hydroelectric Developments and Thermal Generating facilities. The existing architecture is also outdated and requires the existing software to be loaded and ran on each
individual computer at each generating facility. Moving to a new HMI platform will allow for upgrading to a server-based architecture. The HMI Control Software update is a 11 (eleven) million-dollar, multi-year
effort to transition the controls software at all GPSS generating facilities from Wonderware to Ignition. This
project will benefit customers as the transition is integral to the continued safe and reliable operation of our generating units.
As a part of this updated, supporting software and hardware will also need to be upgraded as to
ensure communication and support across all parts of our controls system. The timing of this transition is critical due to the expiring support for both Wonderware and Windows 7 (the current, and only, operating
system functional with Wonderware). Risk likelihood, exposure, and severity increase the longer we
continue to operate on extended service agreements and unsupported technology. The recommended solution was reviewed by GPSS Engineering and approved by GPSS Management.

VERSION HISTORY
Version Author Description Date Notes
1.0 Kit Parker Original submission 7/17/2017 Signed/approved
1.1 Kara Heatherly Conversion to new format 6/20/2020 Includes budget update
2.0 Kara Heatherly Update for current budget projects and
new schedule 7/9/2021
3.0 Kristina Newhouse
& Kara Hensley
Updated to 2022 template and to reflect
most current 5-year plan 8/25/2022

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 112 of 309
HMI Control Software
Business Case Justification Narrative Template Version: 04.21.2022 Page 2 of 8
GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
The existing Human Machine Interface (HMI) software, Wonderware has reached end of life
as support ended in 2017. HMI Control Software is used to develop control screens which are used to control generating systems within Avista Hydroelectric Developments and Thermal
Generating facilities. They allow an operator to run the station from a computer in a control room rather than from the equipment on the generating floor. New control screens need to be
developed using a new software platform. The major driver for the HMI Control Software
business case is the Asset Condition. This project aligns with Avista’s Safe & Reliable
Infrastructure strategy.
The existing architecture is outdated and requires software to be run on each individual
computer. Moving to a new HMI platform will require moving to a server-based architecture.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer Service
Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset Condition, or
Failed Plant & Operations) and the benefits to the customer
Asset Condition: New HMI control software is needed now to prevent limitations going forward that will introduce security risks. The existing HMI software runs on Windows 7, which is
planned to be unsupported after 2020.
Developing new controls screens on a new software platform will modernize control screens
and allow operators to carry out their responsibilities more effectively. Control Screen will need to be developed for each generating facility; therefore, a planned approach will allow
engineering and technicians to develop screens over time to coordinate with control upgrades.
In addition, a new server-based architecture will also create efficiencies for technicians as they
will be able to maintain and update screens remotely.

Requested Spend Amount $11,715,000
Requested Spend Time Period 8 years
Requesting Organization/Department GPSS
Business Case Owner | Sponsor Kristina Newhouse | Alexis Alexander
Sponsor Organization/Department GPSS
Phase Execution
Category Project
Driver Asset Condition
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 113 of 309
HMI Control Software
Business Case Justification Narrative Template Version: 04.21.2022 Page 3 of 8
1.3 Identify why this work is needed now and what risks there are if not approved or is deferred
If we do not stay current with supporting operating systems, then cyber security risks increase. Additionally, continuing operations on unsupported equipment puts our facilities at an
increased risk of technology failure with much longer repair durations and continually increasing costs for support.
1.4 Identify any measures that can be used to determine whether the investment would successfully deliver on the objectives and address the need listed above.
The project execution team (co-led by GPSS and ET PM resources) has established a draft implementation schedule which addresses the following high-level deliverables:
• Develop design standards and validate ET implementation plan – Summer 2021
• Complete GCC PLC Lab (Summer 2021) and Monroe Implementation (new
projected ET completion date: Spring 2022) to provide GPSS and ET opportunities to test screen design and practice conversions in order to minimize impact to generating facilities and outage durations during site installations
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for replacement.
2. PROPOSAL AND RECOMMENDED SOLUTION
The preferred alternative is to purchase new HMI control software that better meets the need of operators, protection control and meter (PCM) technicians, and engineers. Most HMI control
software provides the same functionality but engineers and PCM technicians are interested in software that provides user-friendly installations, interfaces with existing equipment with ease, such
as PLCs, and allows for control screen modifications and troubleshooting with efficiency.
This alternative addresses concerns with unsupported software, such as cyber security vulnerabilities. There is a risk that upgrading HMI software and developing new screens will take longer than expected. The duration of the project could take longer due to complexity, limited outage
availability, or a shortage of resources. To mitigate risk a project manager is needed to maintain schedule and provide ongoing coordination. A Controls Engineer is also needed to consistently
upgrade control screens at each generating facility. Engineering will assist with developing a new
server-based architecture and developing and commissioning HMI control screens, as well as
designing upgrades for the supporting plant infrastructure (namely PLC’s.) The PCM Shop will need at least one full time resource to develop, install and commission the new HMI control screens. A
contractor will be necessary, at least in the beginning, to help establish a new control screen
standard template. Support from the Enterprise Technology (ET) will also be necessary to install new servers at eat plant and provide ongoing support.
Option Capital Cost Start Complete
[Recommended Solution] Purchase new software
platform and develop new control screens
$11,715,000 01 2018 12 2025
[Alternative #1] Upgrade existing software
(Wonderware) and develop new control screens
$1,000,000 01 2018 09 2021
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 114 of 309
HMI Control Software
Business Case Justification Narrative Template Version: 04.21.2022 Page 4 of 8
2.1 Describe what metrics, data, analysis or information was considered when preparing this capital request.
The budgetary refinement for this project has been an ongoing joint effort between GPSS and ET based in constant re-evaluation of actual spend against forecasts. In a lot of ways, this work
is very new to both business units. The level of complexity involved in building network redundancy, designing to new security standards, standardizing controls data points and
hierarchies, and designing custom plant screens and layouts that meet the diverse needs of our plants has proven much more complicated than originally anticipated.
At project inception, an alternatives analysis was conducted between the proposed potential product offerings (Cimplicity, Ignition, Wonderware, etc.) and a cross-functional team of controls
experts, operations staff, PCM technicians and ET operations support staff selected the product
that would be the most scalable to our plants’ diverse needs and the most supportable over
time. The costs of the products were relatively equal and the cost of the effort to bring the plants up to standard (operations on Win10) were distinct from any vendor technology decision.
The decision to add the interface PLCs at some of the plants was a cost-saving to defer the need to expedite the timeline to obsolete the Bailey and Modicon systems - a multi-million
dollars savings to the company’s capital proforma. This decision also allows us to continue to operate safely and reliably on our Bailey and Modicon systems for longer without exposing the
network to undue security risk. Similarly, the decision to replace Unit PLC’s at Noxon, while adding cost to the project, reduced the overall cost to the company by eliminating rework and
replacement cost that would be incurred by the plant in the near future. The estimate savings on this work is $1M.
2.2 Discuss how the requested capital cost amount will be spent in the current year (or future years if a multi-year or ongoing initiative). (i.e., what are the expected functions, processes or
deliverables that will result from the capital spend?). Include any known or estimated reductions to O&M as a result of this investment.
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy
Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]
In accordance with the detailed project schedule, annual projected capital expenditures are in
accordance with the 5-year CPG budget table below.

It is expected that a server-based architecture will reduce O&M costs as it will allow for
modifications to be made to HMI control screens from one central location and eliminate the need to drive to each facility when changes are required. However, the servers will require
ongoing support, therefore increasing O&M costs. Eliminating the extended Windows 7 support contract will also reduce O&M costs.

Year Requested Amount
Prior $7,117,492
2023 $2,600,000
2024 $1,500,000
2025 $500,000
2026 $0
2027 $0
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 115 of 309
HMI Control Software
Business Case Justification Narrative Template Version: 04.21.2022 Page 5 of 8
2.3 Outline any business functions and processes that may be impacted (and how) by the business case for it to be successfully implemented.
The successful implementation of this new control software will improve remote monitoring and
controls at all our facilities, secure and protect Avista’s critical infrastructure, and minimize the
impact of future technology upgrades and versioning on plant operations.
Bringing this system up to date will also ensure continued support from ET Applications,
software licensing and versioning, as well as visibility into potential network and version conflicts. The Ignition design will also provide our PCM techs with real-time support from Controls
Engineering by providing read-only access to the plant control screens from the Mission campus.
2.4 Discuss the alternatives that were considered and any tangible risks and mitigation strategies for each alternative.
The alternatives considered ranged from inaction to complete product replacement. The selection of complete replacement was made based upon the risk/reward analysis performed at
the onset of the project. Maintaining the Wonderware product still posed a near-term risk to operations by continuing a relationship with an antiquated and unsupported product. The
decision to procure and design an entirely new solution better positions Avista for the future and mitigates more of the long-term risks associated with sunsetting technologies.
2.5 Include a timeline of when this work will be started and completed. Describe when the
investments become used and useful to the customer.
Site conversion began in 2020 and will continue in accordance with the table showing the upcoming years within the 5-year plan. These dates reflect anticipated completion dates and
therefore also represent the anticipated schedule for transfers to plant.

2022
Monroe Street
Upper Falls
Control Works
Post Street
2023
Rathdrum
Long Lake
Little Falls
Nine Mile
Noxon Rapids (3 units)
Cabinet Gorge
2024
Noxon Rapids (2
units)
Noxon Rapids
(3 units continued)
Post Falls
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 116 of 309
HMI Control Software
Business Case Justification Narrative Template Version: 04.21.2022 Page 6 of 8

2.6 Discuss how the proposed investment aligns with strategic vision, goals, objectives and mission statement of the organization.
Mission: This project safely, responsibility and affordably improves the level of service we provide to our customers by minimizing direct impacts to services. This innovative approach
allows us to pilot software updates and configurations before implementing on active sites. This in turn, shortens our outage time and allows our operations team to reserve capacity for other
critical needs.
2.7 Include why the requested amount above is considered a prudent investment, providing
or attaching any supporting documentation. In addition, please explain how the investment prudency will be reviewed and re-evaluated throughout the project
One way to evaluate prudency is to consider not only the likelihood of risk but the severity of the outcome in the event of failure. Currently, failure of the controls system at our generating
facilities would be nearly immediately catastrophic. Especially at remote facilities where resources are not physically available to bring systems online and facilities are not staffed to
assume fully manual operations, having a central system “brain” for these functions is essential to keeping the system online and, if necessary, getting the system back online quickly.
Minimizing the severity of non-preventable failure is the prudent and responsible thing to do.
Additionally, operating systems that are no longer supported on extended maintenance
agreements is not sustainable, responsible, or cost effective, and exposes the plants to unnecessary risk.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 117 of 309
HMI Control Software
Business Case Justification Narrative Template Version: 04.21.2022 Page 7 of 8

2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
Stakeholders that interface with the HMI Control Software Business Case include:
• Controls Engineering
• Project Management
• Hydro Operations
• Thermal Operations
• PCM Shop
• ET (Central, Distributed, Network, Security, and Applications)
2.8.2 Identify any related Business Cases
SCCM (09805992) – System Center Configuration Manager (SCCM) must be deployed
to all GPSS production sites prior to the implementation of HMI. SCCM is the vehicle used to distribute the application to the site and to be able to manage updates and
patches remotely from the GCC.
Win10 (09906389) - To the degree that the Windows 10 implementation is delayed out
past HMI’s current implementation schedule, those costs could become the burden of the HMI project or could equivalently impact the HMI installation schedule.
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
The need to address the risk of aging control software and outage control screens has been
vetted through the Generation Production and Substation Support (GPSS) planning process.
The Controls Engineering Manager, along with the assigned Project Manager, will provide
oversight and monthly tracking of the ongoing work within the project.
The Joint ET/GPSS Steering Committee will be comprised of the following members: GPSS
Hydro Operations Manager, GPSS Thermal Operations Manager, GPSS Construction and Maintenance Manager, GPSS Manager of Project Delivery, ET Manager of Systems
Engineering, ET Manager of Applications Delivery, ET Manager of Network Engineering.
3.2 Provide and discuss the governance processes and people that will provide oversight
More detailed project governance protocols will be established during the project chartering process whereby the Steering Committee will allocate appropriate resources to the management of all project activities, once better defined. At this point, we know that an ET and
a GPSS PM will work in tandem to schedule, budget, and allocate resources appropriately to
meet the project execution goals.
3.3 How will decision-making, prioritization, and change requests be documented and monitored
Project decisions will be made at the PM level where appropriate and escalated to the joint ET/GPSS Steering Committee when and if determined to be necessary. Regular updates will
be provided to the Steering Committee by the PM team as project scope, schedule and budget are defined, and through the course of the project execution, change.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 118 of 309
HMI Control Software
Business Case Justification Narrative Template Version: 04.21.2022 Page 8 of 8
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the HMI Control Software and agree with the
approach it presents. Significant changes to this will be coordinated with and approved by the undersigned or their designated representatives.

Signature: Date: 8/25/2022
Print Name: Kristina Newhouse
Title: Controls/Electrical Eng Mgr
Role: Business Case Owner

Signature: Date:
Print Name:
Title:
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 119 of 309
KF_4160V Station Service_Replacement
Business Case Justification Narrative Template Version: 08/04/2020 Page 1 of 7
EXECUTIVE SUMMARY
All generation facilities require Station Service to provide electric power to the plant.
Station Service components include Motor Control Centers, Load Centers, Emergency Load Centers, various breakers, transformers and conductors. Station Service is an elaborate system with multiple built-in redundancies, multiple voltages designed to protect
the plant’s electrical system

The plant low voltage 4160 V switch gear has been identified by AIG insurance inspection as being out of compliance. With aging equipment the plant is experiencing challenges with service and parts to maintains the breakers. The plant is currently installing new fuel
yard equipment which will require new and upsized power needs in the fuel yard. The
plant fuel yard project team has put in place a temporary work around to power the new
yard but this solution is not permenant.
The recommendation is to replace the 4160 V station service. This replacement will
correct the insurance defficency and increase reliability to the plant critical loads. A high-
level cost estimate was received from Columbia Electric and compared to Avista actual
project costs of the from other GPSS locations. If this project is not funded the plant will have more frequent forced outages due to
electrical equipment failures.

This project will impact customers in service code Electric Direct jurisdiction Allocated North serving our electric customers in Washington and Idaho.

VERSION HISTORY
Version Author Description Date Notes
Draft Greg Wiggins Initial draft of original business case 7/8/2021
Rev. 2 Greg Wiggins Revised schedule, costs and offsets 8/20/2022

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 120 of 309
KF_4160V Station Service_Replacement
Business Case Justification Narrative Template Version: 08/04/2020 Page 2 of 7
GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
In recent years, upgrades and maintenance of the Kettle Falls Station Service have
been performed including 480 V breaker remanufacture, 480 V transformer replacements, and MCC replacements. The aging 4160 V breakers were sent to be
refurbished through the 2013-2015 timeframe. However, during the refurbishing
processes not all of the old parts were replaced and parts were misaligned during
reassembly. As a consequence, the plant continues to replace failing parts.
Replacement parts themselves are not readily available and custom fabricated parts have had a tendency to fail and are expensive. In order to meet maintenance needs,
the plant purchases used breakers to strip for parts. The pictures below show some
examples of damaged parts.
Requested Spend Amount $2,135,000
Requested Spend Time Period 3
Requesting Organization/Department GPSS
Business Case Owner | Sponsor Greg Wiggins | Alex Alexander
Sponsor Organization/Department GPSS
Phase Initiation
Category Project
Driver Asset Condition
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 121 of 309
KF_4160V Station Service_Replacement
Business Case Justification Narrative Template Version: 08/04/2020 Page 3 of 7
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
The major drivers for this project are Asset Condtition and Mandatory & Compliance.
The 4160 V gear feeds motors critical to plant operations. Due to the nature of the supplied loads being motors, the equipment is subject to higher operation counts than normal breakers, with two breakers having exceeded 1,700 operations. The frequent
operations add to wear and increase the risk of failure.
The insurance company for the plant has brought up issues regarding the 4160 V
switchgear arrangement as it regards to feeding the Boiler Feed Pumps. According to Paragraph PG-61.1 of the ASME Boiler and Pressure Vessel Codes Section I, one such means of feeding the boiler shall not be susceptible to the same interruption as
the other. The concern revolves around the idea that if one of the Boiler Feed Pumps
is interrupted, the second would need to be able to run and prevent damage to the
boiler. Originally, only one Boiler Feed Pump was electrically driven with the second
driven by steam turbine. At some point the steam turbine drive was replaced with an electric motor. To satisfy the insurance requirements, changes to the 4160 V bus will
need to be made in order to be able to feed the pumps from separate busses. A
potential alternative solution would be to revert the modified boiler feed pump back to
being driven by steam turbine. This solution is being evaluated by the Manager of
Thermal Operations and Maintenance, and is not considered further in this plan.
Another significant change at the Kettle Falls plant is the addition of the new Fuel
Handling System/Fuel Yard Processing Building. The planned design has the power
feed for the new system sourced from the local distribution feeder. This subjects fuel
handling operations to disturbances on the distribution system. To improve the
reliability of operations, a feed from the main station service 4160 V bus to the new fuel yard bus is desired. As the Fuel Yard project moved into the execution stage
there was a cost saving measure to not go with the new service and to add the feed
from the 4160 bus. This is fine but it still only allows for one source to the Fuel Yard.

1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
The equipment that is energized from 4160 V gear is critical equipment to plant
operations such as the ID fan, FD fan, boiler feed water pumps, circulating water pumps and the fuel yard hammer hog. The plant can not run without the ID and FD
fans and there are not redundant fans so the energy source is just as critical as the
fans themselves. The plant is having trouble sourcing replacement parts and have
recently began purchasing used equipment in decent shape to use as spare parts.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 122 of 309
KF_4160V Station Service_Replacement
Business Case Justification Narrative Template Version: 08/04/2020 Page 4 of 7
1.4 Identify any measures that can be used to determine whether the investment would successfully deliver on the objectives and address the need listed above.
Installing the new gear with a tie breaker and supplying the power from two
separate sources will satisfy the insurance defficency. The new fuel yard
equipment will need to have this new power supply to be a complete project.
They fuel yard is scheduled to be commissioned in 2022 or 2023.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
2015 AIG Insurance All Risk Survey Report
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for replacement.
Average of 774 operations. Plant technicians did mention that some of the operation counters
were broken for an unknown period of time and later fixed, so the counts shown are lower than the actuals

2. PROPOSAL AND RECOMMENDED SOLUTION
The recommended solution is to replace the existing switchgear with a new Main-Tie-
Main configuration. Replacing the switchgear directly addresses the concerns
regarding the state of wear of the existing breakers. The new gear would also have a breaker that can be used as a feed to the new fuel yard. This configuration would also
directly address the insurance company’s concerns about being able to feed the two
boiler feed pumps from separate busses. All concerns are addressed with this
alternative. An example of the arrangement is shown below.

Option Capital Cost Start Complete
Replace the 4160 V Station Service with Tie $2,135,000 05/2023 06/2025
Replace the 4160 V Station Service $2,013,000 05/2023 06/2025
Breaker
Position
2A1 2A2 2A3 2A4 2A5 2A6 2A7 2A8 2A9
Operation Count 629 887 630 1829 287 204 736 16 1744
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 123 of 309
KF_4160V Station Service_Replacement
Business Case Justification Narrative Template Version: 08/04/2020 Page 5 of 7
2.1 Describe what metrics, data, analysis or information was considered when preparing this capital request.
.
The plant will need to continue purchasing old breakers to salvage for parts or have custom parts manufactured, maintaining a non-inconsequential O&M burden. This
alternative also does not address the insurance company’s concern regarding the
Boiler Feed Pumps or provide a reliable power source to the new fuel yard.
2.2 Discuss how the requested capital cost amount will be spent in the current year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
Engineering will begin in 2023 followed by procurement in 2024 with the installation
being done during the 2025 annual Spring outage.
Table 1 - Project Cash Flows
Year Recommended Alternative Cash Flow
2023 $95,000
2024 $1,540,000
2025 $500,000

A forced outage caused by a failure on the 4160v bus could extend many months. The estimated daily Power Supply outage cost for this facility is $69,700
(refer to 20220825 Thermal Daily Outage Cost Estimation Tool CONFIDENTIAL.xlsx).
Using an estimated 1 month for an emergency replacement, total Power Supply outage costs due to a failure is estimated to be: $2,091,000

2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
This work will be done during the 2025 annual Spring outage. There will be a short impact and outage to fuel deliveries that will be managed through weekend work

2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
The alternatives discussed around additional costs to mitigate the insurance deficiency and
the added costs were evaluated from Risk Management and a decision was made to install
the tie breaker.
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.

Year
Month Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Intiation
Planning
Execution
Closing
2023 2024 2025
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 124 of 309
KF_4160V Station Service_Replacement
Business Case Justification Narrative Template Version: 08/04/2020 Page 6 of 7
2.6 Discuss how the proposed investment aligns with strategic vision, goals, objectives and mission statement of the organization.
This project aligns with supporting a safe and reliable operating unit.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed and re-evaluated throughout the project
An evaluation was completed by GPSS Electrical engineering and Risk
Management. Both groups supported the project as plant reliability and
insurance deficiency will be resolved with the project.
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
KF Plant Management
KF Plant Techs
GPSS Electrical Shop Crews
GPSS Electrical Engineering
Risk Management

2.8.2 Identify any related Business Cases
Kettle Falls Fuel Yard Replacement Project

3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
GPSS Asset Management
KF Plant Management
GPSS Thermal Operations and Maintenance Manager
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 125 of 309
KF_4160V Station Service_Replacement
Business Case Justification Narrative Template Version: 08/04/2020 Page 7 of 7
3.2 Provide and discuss the governance processes and people that will provide oversight
Quartly status meeting up to construction then weekly meetings.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
Plant management will report changes requests to the GPSS Thermal
Operations and Maintenance manager. Decissions will be made following the GPSS project management process and Corporate Contract Change Order
protocol.

4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the KF 4160 V Station Service
Replacement project and agree with the approach it presents. Significant changes to this will
be coordinated with and approved by the undersigned or their designated representatives.

Signature: Date: 8/20/2022
Print Name: Greg Wiggins
Title: Plant Manager
Role: Business Case Owner

Signature: Date:
Print Name: Alexis Alexander
Title: Director GPSS
Role: Business Case Sponsor

Signature: Date:
Print Name: Thomas Dempsey
Title: Thermal Operations and Maint Mgr
Role: Steering/Advisory Committee Review

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 126 of 309
KFGS - D10R Dozer Certified Power Train (CPT) Rebuild
Business Case Justification Narrative Template Version: 08/04/2020 Page 1 of 7
EXECUTIVE SUMMARY

In 2025 the CAT D10R will reach a milestone service interval and will be requiring a CAT Certified Power Train Rebuild. The power train rebuild includes service to the transmission, final drives,
and engine. This project was first identified from plant maintenance staff and plant fuel equipment
opperators, along with the OEM of the D10R. Using past maintenance logs along with projection of status of the machine and OEM maintenance recommendations it has been determined that
the listed project will be due to be completed. The D10R is one of two critical assests responsible
for moving nearly 500,000 green tons of waste wood around the storage area each year. The primary tasks for this piece of equipment is to move new material out in the inventory storage
area and bring in waste wood fuel to be burned for the plant operations. The 53MW facility cannot
operate on wood waste without the use of a dozer. The facility may be operated on natural gas at 50% reduced generation for short periods of time but it is not classified as a renewable source
and the REC’s are lost when operating in that mode. The listed project is recommended by CAT OEM as part of time based maintenance where
maintenance logs and nearly 30 years of operating history support this action. The cost of completing the project is estimated at $600,000 and preferred to be scheduled during KFGS Annual Outage in 2025 in order to minimize risk to plant availability. This solution will ensure that
the D10R will maintain its reliability which in turn benefits KFGS to continue to generate reliable, safe energy to its customers. If this project is not completed as described above, the D10R will
then be operating above the recommended maintenance interval increasing the likelihood of
catastrophic equipment failure. At that point, the cost to repair would be significantly greater than the price listed as well as have a significant impact on plant operations. To build off that KFGS
would no longer be following a “proactive” maintenance strategy but rather a “reactive” strategy
that given time would have impacts to the company and customers.

The recommendation is to purchase the Certified Power Train. This replacement will
restore the D10R dozer reliabilirt to the plant. A high-level cost estimate was received
from Western States Equipment. If this project is not funded the D10R will eventually have catastrophic failure which will
have a negative impact on plant operations and reliability.

This project will impact customers in service code Electric Direct jurisdiction Allocated North serving our electric customers in Washington and Idaho.

VERSION HISTORY
Version Author Description Date Notes
Draft Patrick Lutskas Initial draft of original business case 06/28/2021
Rev. 1 Greg Wiggins Reviewed cost and schedule 8/20/2022

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 127 of 309
KFGS - D10R Dozer Certified Power Train (CPT) Rebuild
Business Case Justification Narrative Template Version: 08/04/2020 Page 2 of 7
GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
A critical asset (CAT D10R) to the operations of KFGS has reached a milestone maintenance interval and is requiring recommended OEM maintenance.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
The major driver for this project falls around Asset Condition. The D10R is projected to
reach the milestone maintenance interval in the Spring of 2025. KFGS utilizes two CAT
D10’s one is operating until the 250 hour service while the other is on standby, once maintenance is required the standby machine will be put in service. Performing this
work ensures that the redundancy of the critical assets will stay in tact and the machines
can continue to realibly supply wood waste to the facility.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
To date the D10R has 45,858 total operating hours with a projected 56,000 hours of operating when service will be due. OEM (Western States Equipment) recommends
performing a CPT every 10,000 hours. 2,500 hours are put on this machine annually
making 2025 the target for completing the work. Using 30 years of maintenance history it has been noticed that the powertrain has never reached more than 11,000 hours of
operation without a catastrophic failure. For this reason it is critical to complete on
schedule. In 2021 this same work was completed on the D10R which was the first time the dozer had achieved operating hours over 10,000 hours.

Requested Spend Amount $600,000
Requested Spend Time Period 1 year
Requesting Organization/Department KFGS (K07) / GPSS
Business Case Owner | Sponsor Gregory Wiggins | Alexis Alexander
Sponsor Organization/Department GPSS
Phase Planning
Category Project
Driver Asset Condition
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 128 of 309
KFGS - D10R Dozer Certified Power Train (CPT) Rebuild
Business Case Justification Narrative Template Version: 08/04/2020 Page 3 of 7
1.4 Identify any measures that can be used to determine whether the investment would successfully deliver on the objectives and address the need listed above.
If the certified powertrain rebuild is completed as proposed the likelihood of a
catastrophic failure to the D10R would be significantly reduced and the machine will be back to like new condition making for safer operation. This can be measured by Maximo service records and quantifying the number of work orders that are submitted
in the system along with using maintenance expenses broken into year by year expenses to track whether the investment is successful. Ideally one would see a significant drop in service request and maintenance costs after such rebuild.

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
Electronic files are located at plant common drive
Previous D10T Powertrain Rebuild performed in 2018
Previous Powertrain Rebuild performed in 2016 & 2021
CAT OEM Maintenace/Service Manual

1.5.2 For asset replacement, include graphical or narrative representation of metrics associated with the current condition of the asset that is proposed for replacement.

Figure to the right shows the number of
corrective service requests submitted each year. When the operating hours increase the
number of service request and maintenance
costs increase as shown by the D10R’s service history. The first half of 2016 recorded most of
the work as the dozer was rebuilt in June. Following the rebuild maintenance is significantly reduced until the operating hous
reach about 6,000 hours then there is an uptick in work during the last couple of years.

2. PROPOSAL AND RECOMMENDED SOLUTION

Option Capital Cost Start Complete
OEM CAT Certified Powertrain Rebuild $600,000 05 2025 07 2025
Purchase Certifed Rebuild $1,006,560 05 2025 07 2025
Purchase New CAT D10 $2,532,600 05 2025 11 2025
0
5
10
15
20
2016 2017 2018 2019 2020 2021
Submitted Service Requests
D10R
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 129 of 309
KFGS - D10R Dozer Certified Power Train (CPT) Rebuild
Business Case Justification Narrative Template Version: 08/04/2020 Page 4 of 7
2.1 Describe what metrics, data, analysis or information was considered when preparing this capital request.
When deciding to make this request, information gathered from the OEM (WSE) was
used to base the service interval along with the maintenance history supporting the
timeline of each service. Avista’s maintenance planning program (Maximo) was utilized to provide service record history as well.
Costs for each option was gathered from local OEM CAT Dealer and ultimately
weighed benefit versus cost and a decision was made to select the Certified Power Train Rebuild. To build from this, the asset management group was involved planning
similar request as well to analyze options of leasing or even renting an equivalent
machine. Those options were found to not be suitable for long term operation of the equipment.
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include any known or estimated reductions to O&M as a result of this investment.
The capial cost amount will be spent on 2025 as mentioned to complete the power train
rebuild of the D10R. As for estimated O&M reductions, by performing the powertrain rebuild as proposed this will limit the risk of an unplanned catastrophic failure that would impact budgets significantly.
2.3 Outline any business functions and processes that may be impacted (and how) by the business case for it to be successfully implemented.
While the D10R is out for rebuild, the generation facility would be left with just one
dozer (D10T) and the reduncy or back up asset is lost. However, the facility is still able
to operate with the one machine in service but there is a risk involved that if the in-service machine has a failure the facility can not be fed the waste wood necessary to
operate at full load generation. For this reason a schedule to complete this work would
be during the facilities annual outage where the risk would be minimized.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Multiple alternatives were discussed during the course of this request. One being, not
perform the work at all and/or push it out to a later year, this alternative imposed a great risk to the reliability of the plant and was strickened. Alternate two was to
purchase a certified rebuilt machine, this option came at a higher cost and was strickened. Alternative three was to procure an all new machine which was the highest cost option and was strickened. The option that is being proposed is the least cost
option while still accomplishing what is necessary to ensure plant reliability.
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
This project is targeted to begin in May of 2025 with a completion date in early July
2025. The D10R is projected to be out of service for approximately 8 weeks during the CPT as soon as it is returned to KFGS it will be put back in service and considered
used and useful. This projected schedule is to align with the facilities annual outage in
order to minimize risk to the generation
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 130 of 309
KFGS - D10R Dozer Certified Power Train (CPT) Rebuild
Business Case Justification Narrative Template Version: 08/04/2020 Page 5 of 7
2.6 Discuss how the proposed investment aligns with strategic vision, goals, objectives and mission statement of the organization.
One of Avista’s goals is to have safe, reliable energy. A key metric for KFGS is plant
availability, the target percentage is 94% meaning that KFGS strives to be available
when needed. By performing this request the facility will continue to have the necessary redundancy in the waste wood storage area and continue to deliver the waste wood to
the 53MW facililty as planned reliably for the next several years.
2.7 Include why the requested amount above is considered a prudent investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
The timeline to the investment is prudent in order to maintain the proactive maintenance strategy that is currently in place at KFGS. If this is delayed or not accepted the asset will be ran until failure which will have significant operation and budget impacts.
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
Plant operations, supply chain, Western States Equipment, General Fire.

2.8.2 Identify any related Business Cases
Previous D10T Powertrain Rebuild performed in 2018
Previous Powertrain Rebuild performed in 2016 & 2021.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 131 of 309
KFGS - D10R Dozer Certified Power Train (CPT) Rebuild
Business Case Justification Narrative Template Version: 08/04/2020 Page 6 of 7
3.MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
Plant management and Thermal Operations Manager (Thomas Dempsey) will oversee the project.
3.2 Provide and discuss the governance processes and people that will
provide oversight
Plant management and Thermal Operations Manager (Thomas Dempsey) will oversee the project.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
All will be documented in the electronic project folder located in KFGS local common drive.
4.APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the KFGS - D10R Dozer CPT Rebuild
and agree with the approach it presents. Significant changes to this will be coordinated with
and approved by the undersigned or their designated representatives.
Signature: Date: 8/20/2022
Print Name: Gregory Wiggins
Title: Plant Manager
Role: Business Case Owner
Signature: Date:
Print Name: Alexis Alexander
Title: Director GPSS
Role: Business Case Sponsor
Signature: Date:
Print Name: Thomas Dempsey
Title: Thermal O & M Manager
Role: Steering/Advisory Committee Review
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 132 of 309
KFGS - D10R Dozer Certified Power Train (CPT) Rebuild
Business Case Justification Narrative Template Version: 08/04/2020 Page 7 of 7

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 133 of 309
GPSS_KF_Secondary Superheater_Replacement
Business Case Justification Narrative Template Version: 08/04/2020 Page 1 of 10
EXECUTIVE SUMMARY
The Kettle Falls Generating Station processes nearly 450,000 tons of waste wood
annually. During the combustion process the heat generated is transferred to the boiler internal water and steam systems. Water is heated until it becomes steam. The steam is conditioned in the drum before entering two sections of superheater steam pendants.
The first section is the primary superheater which takes high pressure saturated steam
from the steam drum and converts it into dry superheated steam. The secondary
superheater conditions the steam to maintain final steaming conditions at 950 F at 1,550
psi to be used in the steam turbine. The turbine converts the steam into 53 MW’s of green renewable energy.

After a 1997 inspection revealed excessive corrosion caused severe tube wall thinning,
both sections of the superheater were replaced in 1998. The replacement superheater tube material was upgraded from original design with engineering studies showing potential of a 20-year life expectancy from the upgrade. Recent testing from Industrial
Inspection and Analysis revealed the secondary superheater has undergone localized
wall thinning from erosion. The analysis indicates the superheater tubes have
experienced significant non-uniform scaling and tube wall loss on the exterior surfaces up to 54% of the wall thickness.
The recommendation is to replace the secondary superheater. This replacement will
restore plant reliability for Avista’s customers. A high-level cost estimate was received
from boiler maker CH Murphy and compared to Avista actual project costs of the economizer tube replacement project in 2019.
If this project is not funded the plant will continue to have more frequent forced outages
due to secondary superheater tube leaks.
This project will impact customers in service code Electric Direct jurisdiction Allocated North serving our electric customers in Washington and Idaho.

VERSION HISTORY
Version Author Description Date Notes
Draft Greg Wiggins KF_Secondary Superheater_Replace 6/22/2021
Rev. 1 Greg Wiggins Revised schedule, costs, and offsets 8/20/2022 Revised schedule and cost

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 134 of 309
GPSS_KF_Secondary Superheater_Replacement
Business Case Justification Narrative Template Version: 08/04/2020 Page 2 of 10
GENERAL INFORMATION

1. BUSINESS PROBLEM
The Kettle Falls Generating Station thermal
plant is a wood fired natural circulation boiler. The wood is burned on a traveling grate system
and the heat from the fire is transferred into the
boiler water walls, superheater, generation
section, economizer and air heater. The
process begins with pumping water through a series of heat exchangers to add energy to the
boiler water.
The boiler water is heated to steam at 415,000
lbs/hr of steam flow. The saturated wet steam
passes through two sections of superheater tube bundles. The first section is the primary
superheater followed by the secondary
superheater. Steam exits the secondary
superheater at 950 F superheated steam at
1,550 psi operating pressure to drive the steam turbine generator. The steam is then
condensed back into water and is pumped back
through the heating system again.
During the combustion process fly ash is
carried in the flue gas stream up the furnace and through the superheater, generation bank and economizer. The fly ash is corrosive and abrasive by nature. Over the past 23 years
the fly ash has caused random thinning to the outside of secondary superheater tube
walls.
Requested Spend Amount $2,800,000
Requested Spend Time Period 2 years
Requesting Organization/Department K07 / GPSS
Business Case Owner | Sponsor Greg Wiggins I Alexis Alexander
Sponsor Organization/Department K07 / GPSS
Phase Initiation
Category Project
Driver Asset Condition
Secondary
Superheater
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 135 of 309
GPSS_KF_Secondary Superheater_Replacement
Business Case Justification Narrative Template Version: 08/04/2020 Page 3 of 10
1.1 What is the current or potential problem that is being addressed?
The secondary superheater is reaching the minimum tube wall thickness for safe and reliable operations of the plant. The thin areas cause tube failure as the high-
pressure steam inside the tube bursts the thin tube wall. The plant must be taken
offline to make the repairs. Depending on the severity of the leak the unit might
need to be taken offline immediately but can sometimes run for a few weeks until
the best economic opportunity allows for the shutdown to be scheduled. If the unit
is left running with a superheater tube leak the steam blowing from the tube may hit
an adjacent tube steam cut through the metal and create another tube leak. The random thinning and scale make it impossible to predict when and where the next
tube leak will occur.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
Major driver for this project is Asset Condition. The superheater is a critical
component of the boiler circuit. Without the superheater the plant is unable to
generate electricity. Restoring the superheater will increase plant reliability.
1.3 Identify why this work is needed now and what risks there are if not approved or is deferred
The plant will continue to experience forced outages due to superheater tube leaks.
Repairs, outage duration and costs vary depending on location of the leak and the
number of tubes that have been impacted. Repair costs vary from $30k to $125k with outages lasting between 48 hours to a full week.
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
Plant reliability will increase as the unit has been averaging a couple tubes leaks a year since 2012. Non-destructive testing will be able to monitor tube integrity with new baseline data which will help predict the when the next replacement should take
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 136 of 309
GPSS_KF_Secondary Superheater_Replacement
Business Case Justification Narrative Template Version: 08/04/2020 Page 4 of 10
place. Previous study from JP Industrial in 1997 expected a 20-year operating cycle
on the previous superheater replacement which was reached in 2018.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
JP Industrial – Superheater engineering study – Kettle Falls Plant Library This
engineering study was completed in 1997. It included tube analysis completed by an
independent firm McDermott Technology. The study focused on the superheater tube
failures and root causes. The JP Industrial report suggested a replacement superheater
could expect to have a 20-year operating lifespan under similar operating conditions.
5 Star Non-Destructive Testing Reports – Kettle Falls Outage Files Annual Outage NDT
inspection reports beginning in 1990 continuing every other year to current year. These
inspection record tube thickness of key areas of the boiler.
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for replacement.
The boiler graph above is used during the annual outage to measure key areas of
the boiler. Areas include the water walls, chill tubes, primary and secondary
superheaters, generation bank and economizer tube. A contractor uses non-destructive testing equipment to accurately measure the thickness of the tube walls
and compare to a new tube. Show in the chart is the color-coded measurements
showing different levels of concern. Colors blue and green are considered in good
condition. Pink color is concern while Red is must repair. Focus areas of the
secondary superheater are found in the G, H, I, and J. Each tube is measured roughly in the same spot every two years. Pink areas are indicating issues while
Red indications require repairs to maintain the boiler operating license from the
State.
5 Star Testing is a contractor that has been recording the tube data for the plant
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 137 of 309
GPSS_KF_Secondary Superheater_Replacement
Business Case Justification Narrative Template Version: 08/04/2020 Page 5 of 10
for over 20 years to maintain accurate and consistent inspection practices and test
results. During plant outages, scaffolding is installed to gain access to key areas of the boiler so these reading can be recorded. Sometimes scaffolding is not built
due to outage duration, so those areas are recorded as NO ACCESS. Below is
the data take over a six-year interval. In 2014 there were no areas of concern
recorded in the secondary superheater section. In 2016 scaffolding was not
installed to gain access to area I. The 2016 outage revealed several tubes reaching a measurement of concern. Tube shields were installed to prolong the
life of the tubes recorded in pink. Those tubes are no longer measured, and some
thermal conductivity efficiency is reduced to extend the life of the tube. In 2018
section in I were also recorded as a warning area.
2014 2016 2018

NOTE: No data was collected in 2020 or 2021 due to COVID
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 138 of 309
GPSS_KF_Secondary Superheater_Replacement
Business Case Justification Narrative Template Version: 08/04/2020 Page 6 of 10
2. PROPOSAL AND RECOMMENDED SOLUTION
The recommendation is to replace the secondary superheater section. During the
1998 superheater tube replacement project both sections were replaced. A decision was made to upgrade the material and tube thickness on both sections of superheater. The primary superheater was upgraded from a 209 T1 material with a
minimum wall thickness of 0.149” to a 213 T11 material with a minimum wall thickness
of 0.198 wall thickness. These upgrades to have extended the primary superheater
life span based on NDT results and analysis. Currently there are no indications showing in the Pink. Although there would be some savings in mobilization and common work and equipment needed to replace secondary superheater it is unknow
how long the primary superheater will continue to operate without any impact to
reliability. The last NDT inspection on the primary superheater showed some slight
thinning on the tube bends only shown in D area.

2018 Primary Superheater

Option Capital Cost Start Complete
Replace the Secondary Superheater $2,800,000 MM YYYY MM YYYY
Alternative 1 Replace Primary and Secondary
Superheater
$4,000,000 MM YYYY MM YYYY
2.1 Describe what metrics, data, analysis or information was considered when preparing this capital request.
The first superheater was replaced after 16 years of service. The material of
the tubes was changed from original design. The 1998 JP Industrial project
report suggested the upgraded materials would possibly provide 20 years of
service. The plant performs non-destructive testing to monitor the superheater
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 139 of 309
GPSS_KF_Secondary Superheater_Replacement
Business Case Justification Narrative Template Version: 08/04/2020 Page 7 of 10
tube thickness. These readings are
performed every two years and small repairs and preventive measures have been taken
such as tube shielding to ensure maximum
service is reached from the tubes. Below is
a photo of an area that was replace and
shielded. These repairs are scheduled and managed during the annual outage to
minimize plant down time. Through
consistent non-destructive testing a long
data set has been collected on the entire unit
and the secondary superheater is showing significant tube thinning. Nearly 80% of the
tube leaks in the past 15 years have been
located within the secondary superheater.
About 60% of those leaks have caused
forced down time on the unit while the other 40% were discovered during scheduled outages. The secondary superheater
has operated longer than expected and has thinning throughout the entire
pendant. Data shows ongoing maintenance of sections will no longer be a
viable option as much of the pendant has reached the Pink measurement.

2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
The secondary superheater replacement project will consist of a multi-year project with the first year being the procurement of the superheater tubes. Year
two will be the installation of the superheater as part of the annual Spring
outage. The benefits to completion of this project will be increased reliability to
the plant. Some O&M savings will be recognized in scaffolding costs, material
and repair services.
A forced outage caused by a failed superheater tubes could extend many
weeks. The estimated daily Power Supply outage cost for this facility is $69,700
(refer to 20220825 Thermal Daily Outage Cost Estimation Tool
CONFIDENTIAL.xlsx).

[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy
Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
This project will be managed within the normal Spring annual outage and will not have any additional impacts to Power Supply
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 140 of 309
GPSS_KF_Secondary Superheater_Replacement
Business Case Justification Narrative Template Version: 08/04/2020 Page 8 of 10
2.4 Discuss the alternatives that were considered and any tangible risks and mitigation strategies for each alternative.
Mitigation strategies have been in place for the past 5 years and will continue
with smaller O&M projects and repairs. The NDT data is suggesting full tube
replacement is now needed instead of isolated small sections of tube
replacement or shielding. Due to COVID contractor restrictions no data was
collected in 2020 or 2021. With historical data it the plant can expect to see more tubes in the all three sections of the secondary superheater to reach the
Pink status and most likely some Red tube repairs will need to be made before
this project is completed.
2.5 Include a timeline of when this work will be started and completed. Describe when the investments become used and useful to the customer.
Depending on material supply, procurement process will begin 6 – 12 months
prior to the installation of the superheater tubes. A recent project that was
completed at the plant with the economizer tube replacement had a similar
approach. The economizer tubes were sources out of South Korea then
shipped to Mexico for fabrication. The tube bundles were shipped to the plant a month prior to installation. CH Murphy was selected to install the economizer
and work began two weeks prior to the beginning of the annual Spring outage
and was complete in 4 weeks. This project will transfer to plant upon project
completion.
2.6 Discuss how the proposed investment aligns with strategic vision, goals, objectives and mission statement of the organization.
This project aligns with providing safe and reliable renewable energy for our
customers.
2.7 Include why the requested amount above is considered a prudent investment, providing or attaching any supporting documentation. In addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
This project will invest into a base load renewable facility that will increase plant
reliability. The initial superheater was replaced after 16 years of service. The
current secondary superheater has been in service for 23 years and will be at 26 years of service at the time of replacement. The plant can not operate without
the superheater and data shows most of the tubes have reached a critical point
needing to be replaced. Once replaced NDT testing will continue tracking the
new tubes as before to ensure proper maintenance and planning is documented
for future replacement.
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
Thermal Operations and Maintenance Manager
Plant Manager
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 141 of 309
GPSS_KF_Secondary Superheater_Replacement
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Thermal Engineer
Kettle Falls Specialist
Supply Chain

2.8.2 Identify any related Business Cases
None
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
Thermal and Operations Maintenance Manager
Plant Manager
GPSS Thermal Engineer
3.2 Provide and discuss the governance processes and people that will
provide oversight
This project will be managed similarly past project such as the recent
economizer replacement project. The Plant Manager will work closely with the Thermal Engineer and/or Project Contract Engineering to manage the
procurement, fabrication and installation of the secondary superheater. Status
reports and monthly update meetings will be made to the Thermal Operations
and Maintenance Manager up until the installation process begins then weekly
progress meetings will be used to keep the group informed.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
This project will utilize Corporate Supply Chain Contract Change Order process
for any changes to scope, schedule and budget changes. The project will follow
the GPSS Department Project Delivery process. Issues or concerns will be brought to the GPSS Thermal Operations and Maintenance Manager for
guidance and approval.
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Kettle Falls Secondary Superheater
Replacement Project and agree with the approach it presents. Significant changes to this will
be coordinated with and approved by the undersigned or their designated representatives.

Signature: Date: 8/20/2022
Print Name: Greg Wiggins
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 142 of 309
GPSS_KF_Secondary Superheater_Replacement
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Title: Plant Manager
Role: Business Case Owner

Signature: Date:
Print Name:
Title: Director of GPSS
Role: Business Case Sponsor

Signature: Date:
Print Name: Thomas Dempsey
Title: GPSS Thermal Ops & Maint Mgr.
Role: Steering/Advisory Committee Review

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 143 of 309
KF_Fuel Yard Equipment_Replacement
Business Case Justification Narrative Template Version: 08/04/2020 Page 1 of 12
EXECUTIVE SUMMARY

The existing system does not allow the plant to operate consistently with safe best practices, environmental stewartship and production. The fuel handling equipment
operates at or beyond its absolute limit. In the early 1980’s Washington State increased
the legal hauling weight and the trucking industry transitioned from 48’ trailers to 53’ to
increase their payload. This change created a number of production and safety
challenges for the plant operations and contractor support. The system does not meet current environmental regulations for visibility and particulate matter (PM) emissions for intermittent periods. Although the primary drivers for the project are safety,
environmental, and reliability, we do expect a decrease in O&M. With all benefits
included, Financial Planning and Analysis has concluded that this is a prudent project.
The project will proceed over a two year period with $12 million in 2019 and $10 million in 2020. (7/8/2021 Update: Project timeline has been extended and adjusted and the
current plan will continue into 2021 with the underground utilities installed, major
equipment purchased and truck dumpers commissioned. 2022 will be construction of
conveyance, processing and control buildings and installation of the hog and disc screen.)
Replacing the major fuel handling equipment will create a safer system for employees and contractors as the new dumpers will be designed to lift current truck lengths and weights. The major equipment will be designed with covers and passive dust control
utilizing new dumper technology and conveyance covers. (7/8/2021 Update: Scope has
been reduced to reduce project costs by changing the truck route, eliminating a pass
through travel route, reduction of an enclosed processing building, eliminating a conveyor
through a more compact layout, eliminating a new power supply from the distribution line
near the plant site and delay of replacing the existing #3 fuel conveyor)

This project will impact customers in service code Electric Direct jurisdiction Allocated
North serving our electric customers in Washington and Idaho.

VERSION HISTORY
Version Author Description Date Notes
Draft Greg Wiggins Initial draft of original business case 05/01/2018
1.0 Thomas Dempsey Edit Draft / Executive Summary 07/03/2018 Added content
1.1 Greg Wiggins Edit Approved Business Case to new
Template 07/08/2021
New Template / Update major
project changes Scope,
Schedule and Budget

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 144 of 309
KF_Fuel Yard Equipment_Replacement
Business Case Justification Narrative Template Version: 08/04/2020 Page 2 of 12
GENERAL INFORMATION

1. BUSINESS PROBLEM
The major fuel yard equipment being
considered for replacement includes
the truck dumpers, fuel hog, truck scale, and conveyance systems.
Truck Scale - The truck scale is
used to account for the quantity of
fuel received from each truck
delivery. The truck drivers scale in upon arrival to the site and the scale
out after completing the unloading
process.
Truck Dumpers - The truck dumper
receives the delivered fuel by elevating the trailers. Fuel exits the
rear of the trailer into a receiving
housing.
Fuel Conveyors - Fuel conveyers move the fuel from the truck dumpers to a metal
detection system, then to the fuel hog system and finally out to the fuel yard.
Hog and Disc Screen - The fuel hog is a device that clarifies and conditions the fuel
so that it is the proper size required for optimum combustion.
1.1 What is the current or potential problem that is being addressed?
There are three key components that comprise the business problem presented
by the current fuel yard.
1. Safety
2. Environmental
3. Reliability
Requested Spend Amount $22,000,000
Requested Spend Time Period 2 year (7/8/2021 Update project will be 5 year)
Requesting Organization/Department GPSS
Business Case Owner | Sponsor Greg Wiggins | Andy Vickers
Sponsor Organization/Department GPSS
Phase Execution (7/8/2021 Update project is in execution phase)
Category Project
Driver Asset Condition
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 145 of 309
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These three components are summarized as follows:
The Kettle Falls Generating Station is a biomass fueled power plant that processes on average 500,000 green tons of waste wood from area sawmills. The wood delivered to
the facility is trucked in by contractors utilizing semi-trucks and chip trailer. On average
the plant received 65-80 loads of fuel each day with surges to 100 deliveries in a 24 hour
period.
The plant’s original design was just prior to Washington State increasing the legal haul
lengths and weights. All the equipment was designed for 48’ trailers and the new law
change in 1985 allowed drivers to haul with 53’ trailers. When the drivers enter the facility
the load is weighed on a State certified scale to determine amount of fuel being delivered.
The longer trailers do not completely fit on the scale without the drivers lifting the tag axle
on the trailer. The plant’s delivery tracking system captures the gross weight of the truck and trailer into the 3Log financial interface application. Through this system vendors and
suppliers are paid for their services. Due to the longer trailers and short scale drives can
“cheat” the system by not positioning the load correctly on the scale. Each load is
reviewed through the 3Log (TWA) Truck Weight Analyzer. When an infraction is found
the surveillance video is reviewed and sent to the hauling company for reconciliation. Manual adjustments are made in the system to ensure proper payment to the supplier.

Truck was intentionally positioned short on the scale. TWA show drivers manipulating the scale due to being overloaded.
The fuel is offloaded truck trailers into the receiving hoppers via a truck dumpers. The
wood is then conveyed, screened and sized prior to being transferred out to the fuel
inventory pile. The Fuel Equipment Operators then manage the fuel inventory utilizing D10 Cat dozers to stack out incoming fuel and stage inventory to be processed in the
plant.
Due to the higher legal hauling limits in Washington the longer truck/trailer configurations
require the truck drivers to unhitch the trailer from their trucks. This unhitching process
not only increases truck turnaround time and increases hauling costs to plant, it adds a difficult step. Although not the primary factor, a contractor fatality in 2013 occurred while
going through this step in the process. One driver was attempting to unhitch his trailer
from the truck and was working with another driver to get the hitch pin released when the
accident occurred.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 146 of 309
KF_Fuel Yard Equipment_Replacement
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After the load is raised into the air and the fuel is discharged out of the back of the haul
trailer into the truck receiving hopper a large plume of dust often launched into the air and
then carried in the wind off the plant
site. After the wood discharges out of the truck receiving hopper it is transferred via conveyor belt to a
disc screen and hammer hog to be
properly sized and then discharged
onto the hog storage area.
Both Safety and Environmental regulations require that PM be
reasonably controlled for worker
safety, air quality and visibility. All
emissions should be managed on-site.
The fuel yard is subject to a very corrosive environment due to the wet wood being in
contact with the equipment. The years of rusting has caused failure to metal conduit and
structural steel. The metal support structure of the truck receiving hoppers has rusted
through to the point of being completely cracked through. Welded plates have been installed to affected areas on the truck receiving dumpers. Many of the electrical conduits are rusted through and need replacement.
The system is currently running at maximum capacity with fuel spilling over the edges of
the conveyance system, the disc screen is not operating at the proper throughput as a
significant amount of proper sized fuel is carried over the disc screen into the hammer hog. The over feeding of material into the hog creates excessive wear on the hammer hog grates and hammers.
With an average of 80 semi loads delivered each day and over 25 sawmills depending on
the fuel yard at Kettle Falls to be in full operation there is tremendous pressure in keeping
the system running. Area mills store the fuel purchased by Avista in storage bins and can only hold the waste wood for a few days and sometimes only hours before the backup of wood begins to cause production issues at the mill. When product flow out of the mill is
not managed well suppliers may begin to look for other options to move their waste to
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 147 of 309
KF_Fuel Yard Equipment_Replacement
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more reliable markets. Another important detriment to not keeping fuel moving efficiently
is that as more fuel inventory builds at the supplying mill, the resulting Moisture Content
increases as well as the opportunity for contamination from rock and other “non-spec”
materials. It is important to keep the KFGS fuel yard operating with minimal downtime
to provide good service and quality control to the supplier’s milling operations. It is critical
to the reliability of both the KFGS plant and its supply chain.
In 2017 a team was assembled including the Thermal Operations and Maintenance Manager, Fuel Manager, Plant Manager, Thermal Engineering and plant staff. The team
worked with outside engineering firm WSP to evaluate the fuel yard equipment and
explore options. The team also traveled to two new biomass plants to gain knowledge of
new equipment and process. This information along with the support of WSP allowed the
team to evaluate a number of options.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
Major drivers for this project were Asset Condition and Mandatory & Compliance. Installing the new fuel yard equipment with a higher capacity design and
environmental dust control measures will be a benefit to the plant and neighbors.
Moving truck through the yard quickly reduces trucking costs. This project will
decrease truck turn time.
1.3 Identify why this work is needed now and what risks there are if not approved or is deferred
The plant experienced a fatality of a contract driver that would have been completely
avoided if the truck dumpers were able to lift the current truck weights and lengths.
A few years later another driver was injured on plant site attempting to manually
offload his overloaded trailer when a bunch of fuel slid out of the trailer and buried the driver crushing his hip and knee. This project will make for a safer facility for our
contractors.
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the need listed above.
Truck weight analyzer and the weighwiz system will be able to accurately capture
the delivery with the new longer scales. Truck turntime will decrease as drivers will
no longer need to lift tag axels, disconnect the truck and trailer or use one scale for
inbound and outbound scaling.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
In 2017 a team was assembled including the Thermal Operations and Maintenance Manager, Fuel Manager, Plant Manager, Thermal Engineering and plant staff. The team worked with outside
engineering firm WSP to evaluate the fuel yard equipment and explore options. WSP presented the Team a feasibility study with options to consider. That document is located in the project file.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 148 of 309
KF_Fuel Yard Equipment_Replacement
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1.5.2 For asset replacement, include graphical or narrative representation of metrics associated with the current condition of the asset that is proposed for
replacement.
The team selected option #3 and in replacing the major equipment in a new layout.
Below shows the four options, matrix score, CAPX and OPEX.
2. PROPOSAL AND RECOMMENDED SOLUTION
The four options were discussed and doing nothing has been the approach for a number of years. Maintenance costs have increased with equipment failure to the
live bottom gear boxes, dumper cylinders and lifting deck. Modifications are being
made to equipment due to obsolete equipment is no longer available. This
approach will see continued breakdown maintenance, reduction in fuel yard reliability and continued risks around safety and environmental litigation.

Option 1 includes major rebuild of the existing equipment. The truck dumpers
would have mechanical and support rebuilt, some conveyors would be sped up to
the maximum allowed throughput, hog and disc screen would be rebuilt, the power distribution, motor control centers and PLC’s replaced, all the electrical hardware in the yard would be replaced. This option would not change the operations of the fuel
handling system. Safety and environmental concerns would remain unchanged.
The truck scaling issue would still remain. The work would create major disruptions
to our suppliers as the work and repairs could not be done without interrupting
delivery schedules for days and weeks at a time. Fuel would have to be diverted to other consumers with the risk of losing the contracts in the future.

Option 2 included replacing key equipment with one new scale, two dumpers, two
conveyors, hog and screen in the existing location. This option would not address
the congested truck route that currently exists with one scale. The fuel conveyor angle would remain the same and would not solve the sliding winter fuel issues
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 149 of 309
KF_Fuel Yard Equipment_Replacement
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experienced by the plant operations staff all winter long. This option would disrupt
dilveries and cause major fuel disruptions to the sawmills and carriers under contract. Temporary truck dumpers would have to be installed and significant fuel
curtailment and deverting would be required.

Recommendation is to pursue Option 3 that includes relocating new equipment to a
different location in the fuel yard. This approach would allow the current system to operate while the new system is constructed and commissioned. The layout would
reduce crossing traffic issues with the semi trucks. A new longer inbound and
separate outbound scales would eliminate the scaling issue as sensors would not
allow a driver to scale in unless the truck was positioned correctly on the scale. The
two new truck dumpers would be larger in size which would allow the lifting of both the truck and the trailer. This would reduce truck turnaround time and eliminate the
hazard identified in the driver fatality. The new dumpers would incorporate a dust
containments systems to reduce fugitive dust during the offload. New conveyors
would be larger to accommodate higher throughput. The higher capacity belt
system would reduce laborious shoveling of spilled fuel. The incline of the new belts would reduce winter frozen fuel from sliding on the conveyor belts. The disc
screen would be larger in size for better screening efficiency and reduce hog
operation to only oversized material. The upgraded stack out fuel conveyor system
would strategically move the fuel to three locations reducing Caterpillar dozer fuel
consumption and yearly time base maintenance. A new control tower and power supply would eliminate the electrical deficiencies with the current system.

Option 4 is the same as option 3 with the addition of a covered fuel storage area.
Covering the fuel could reduce moisture content during the winter months. Power
Supply and Asset Management explored the additional cost benefit and this option did not make financial sense.

Option Capital Cost Start Complete
Existing Rebuild and Minor Upgrades $4,200,000 10/2020 6/2023
Existing Layout with New Equipment $9,500,000 10/2020 6/2023
New Layout with New Equipment $22,000,000 10/2020 6/2023
New Layout with New Equipment and Covered Yard $30,100,000 10/2020 6/2023
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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2.1 Describe what metrics, data, analysis or information was considered when preparing this capital request. The Team worked with WSP and evaluated ever component of the fuel
handling system. All of the current equipment was ranked using the GPSS
project ranking matrix and the scores were used to determine what system
would meet the criteria set for the project. Below is an example of the analysis
that was done for every part of the fuel handing system.
Reference key points from external documentation, list any addendums, attachments etc.

2.2 Discuss how the requested capital cost amount will be spent in the current year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
The project will be a two year project with engineering, design and major
equipment procurement in the first year followed by construction and
commissioning the following year. The beakdown is a two year period with $12 million in 2019 and $10 million in 2020. (7/8/2021 The project will run into 2022
with a possibility of 2023. The project originally requested 22 million over two
years, CPG has only funded 20 million. When presenting the request I failed to
load the project during the estimating process so AFUDC and Loadings were
not added at the time of the request. These two issues have a 4 million shortfall
in project funding. During construction the underground excavation process
discovered unforeseen challenges with foundations and underground piping
that resulted in re-engineering and changes. Cost and overruns form the phase
one resulted in the Team drastically cutting scope to manage budget. Changes
included re-routing the truck area, removing the enclosed processing building,
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 151 of 309
KF_Fuel Yard Equipment_Replacement
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repurposing some existing equipment, redesigning the layout to eliminate an
entire conveyor and postponing replacing the final stackout conveyor.)
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
This project will require some short outages that will be managed within the normal Spring outage for accommodate some conveyor transitions to the
current process and power supply connections. There may be some curtailment
needs with our contract mill to stop wood deliveries. This project will not cause
any plant reliability issues with Power Supply.

2.4 Discuss the alternatives that were considered and any tangible risks and mitigation strategies for each alternative.
The project will run into 2022 with a possibility of 2023. The project originally
requested 22 million over two years, CPG has only funded 20 million. When
presenting the request I failed to load the project during the estimating process so AFUDC and Loadings were not added at the time of the request. These two issues have a 4 million shortfall in project funding. During construction the
underground excavation process discovered unforeseen challenges with
foundations and underground piping that resulted in re-engineering and
changes. Cost and overruns form the phase one resulted in the Team drastically cutting scope to manage budget. Changes included re-routing the truck area, removing the enclosed processing building, repurposing some
existing equipment, redesigning the layout to eliminate an entire conveyor and
postponing replacing the final stackout conveyor. The Team intentionally
stopped work with the contractor Greenberry to reevaluate the costs. The installation was rebid to a number of contractors and a change was made with awarding the work to Knight Construction as a lower cost.
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
(7/8/2021 Update All of the underground work is complete minus two conveyor
foundations that will be installed after the current truck dumpers are demolished.
All major equipment is purchased and onsite minus the hammer hog and
transition chute and the #3 stack out conveyor. The fueling building is procured
and will be installed in September. The truck dumpers will be commissioned
mid July. All the critical electrical equipment has been purchased. The project
has two options for 2022 one being a complete project to the #3 conveyor and
the other a hot feed option which could see some of the equipment in Q3 of
2022 either way. If the hot feed option is selected then the remaining equipment
would become operational in 2023.)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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2.6 Discuss how the proposed investment aligns with strategic vision, goals, objectives and mission statement of the organization.
Ketlle Falls is a renewable generating site and this project aligns with providing
reliable renewable energy to our customers. This project will increase Safety
and be good for the environment and neighbors.
2.7 Include why the requested amount above is considered a prudent investment, providing or attaching any supporting documentation. In addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
This project was subjected to a rigorous evaluation of each major piece of
equipment and is documented in the WSP Feasibility Study. The project has
worked closely with the Steering Committee that is represented by GPSS, Environmental and Power Supply. The project is being lead by GPSS Project
Manager and the Team meets regularly to discuss scope, schedule and budget.
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
GPSS Thermal Operations and Maintenance Manager
Environmental
Power Supply
Contracts and Supply Chain
Plant Staff
2.8.2 Identify any related Business Cases
KF 4160 V Station Service replacement (new request in 2022)

3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
Thomas Dempsey - GPSS Thermal Operations and Maint Mgr
Darrell Soyars – Environmental
Scott Reid – Power Supply
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 153 of 309
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3.2 Provide and discuss the governance processes and people that will provide oversight
GPSS Core team will follow the Department Project Management protocol.
There will be monthly Steering Committee meetings to discuess issues or
concerns. Updates will be shared on an as needed basis between monthly
status meetings.
3.3 How will decision-making, prioritization, and change requests be documented and monitored
Chage orders will follow Supply Chain contracting protocol based on financial
signing authority.

4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Kettle Falls Fuel Yard Equipment
Replacement project and agree with the approach it presents. Significant changes to this will
be coordinated with and approved by the undersigned or their designated representatives.

Signature: Date: 7/8/2021
Print Name: Greg Wiggins
Title: Plant Manager
Role: Business Case Owner

Signature:

Date: 7/9/2021
Print Name: Andy Vickers
Title: Director GPSS
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Role: Steering/Advisory Committee Review

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 155 of 309
KF - 2022 ID Fan & Motor Replacement
Business Case Justification Narrative Template Version: 04.21.2022 Page 1 of 9
EXECUTIVE SUMMARY
The induced draft (ID) fan at Kettle Falls Generating Station is a critical component in the
combustion process. The ID fan pulls a draft on the combustion fire box and discharges
the flue gas through the electrostatic precipitator and out the stack. The ID fan is
considered a “dirty” fan in which it is operating with fly ash in the flue gas. The fly ash is abrasive on the internal components of the boiler. The fan shroud, case, cage and dampers are requiring significant annual maintenance each year to build up the worn
area. The fan motor reaches max amperage during wet wood combustion and often hits
the max fan damper position.
The proposed solution involves replacing the ID fan and motor to appropriately accommodate the needs of the plant. The proposed solution includes implementing a
variable frequency drive (VFD) which addresses fluctuations in loads expected from fuel
moisture and the ability to operate in a flexible EIM market. The VFD also improves fan
and motor efficiency during operations minimizing the wear that has become an annual
maintenance concern. The change in equipment will precipitate ducting changes and potential foundation modifications. This solution has been the result of a collaboration
between plant management (Greg Wiggins and Patrick Lutskas) and plant technical staff.
Project scope has also been reviewed and approved by the program manager (Thomas
Dempsey). The proposed solution is budgeted to cost $1,650,000. The investment of the
ID fan and motor replacement (along with a VFD) will eliminate the costly repairs which have only allowed the unit to limp from year to year. This is not only necessary to ensure
the plant is able to operate under full load with the expected range of fuel quality. All of
this adds value to the customer through improved operations and minimized maintenance
costs. There has been significant work with Air Stream, a fan manufacturer, in the testing,
sizing and cost estimating for this project. Options and recommendations have been captured and this project has been well scoped and estimated.
VERSION HISTORY
Version Author Description Date Notes
Draft Derek Babine Initial draft of original business case 05/24/2022 Executive Summary Only
1.0 Derek Babine Updated to include project justification 08/24/2022 Full business case
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 156 of 309
KF - 2022 ID Fan & Motor Replacement
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GENERAL INFORMATION
1.BUSINESS PROBLEM
The induced draft (ID) fan at Kettle Falls is a part of the flue gas system which pullsa draft on the combustion fire box and discharges the flue gas through the
electrostatic precipitator and out the stack. The ash in the fuel gas is abrasive which
has caused significant wear to all of the fan components and case. The motor driving
the fan is also suffering from being overworked during times of poor fuel quality and
high demand on the system at full load. This sometimes results in a need to limit the
plant’s output because the motor cannot keep up with the material that the fan is
processing. Currently, the plant uses inlet guide vanes (or dampers) to regulate the
flue gas entering the fan chamber. This ensures that the fan does not get
overloaded. These dampers are only able to aid the process of the flue gas so much
before the motor is maxed out and the plant is forced to drop megawatts.
In short, the mounting maintenance costs for the fan and the inability for the motor
to keep up with the volume and quality of flue gas led to higher costs and lost
generation.
Requested Spend Amount $1,650,000
Requested Spend Time Period 2 years
Requesting Organization/Department K07 / GPSS
Business Case Owner | Sponsor Derek Babine | Alexis Alexander
Sponsor Organization/Department K07 / GPSS
Phase Initiation
Category Project
Driver Asset Condition
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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KF - 2022 ID Fan & Motor Replacement
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1.1 What is the current or potential problem that is being addressed?
The induced draft fan faces significant maintenance nearly every annual outage
as a result of fan blades wearing down from fly ash abrasion. Usually, these
repairs come in the form of welding additional material on the blades and
grinding it down to maintain the effectiveness of the fan. This is costly and difficult work which does not address the root problem, that the fan is nearing
the end of life. The motor also maxes out in amperage and is unable to
accommodate the flue gas flow under certain conditions.
1.2 Discuss the major drivers of the business case
The main driver of the business case is certainly asset condition but there is also a performance and capacity issue as the fan and motor age, they are no
longer able to process flue gas to the degree necessary under certain operating
conditions which can limit the capacity of the plant.
1.3 Identify why this work is needed now and what risks there are if not approved or is deferred
The fan and motor limp along each year thanks to extensive maintenance but
the effective longevity of this strategy is unknown. If the fan has severe enough
wear, the plant would be forced to come offline due to an inability to process flue
gas. While the repair costs continue to build, there is also the possibility of
unplanned plant downtime if the fan or motor needs to be replaced in the case of equipment failure. Additionally, this project has already been deferred for
several years.
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the need listed above.
As a result of the proposed project, the plant will see a large reduction in annual
maintenance to the fan for the next 10-20 years. Any repairs will be minimal by
comparison. Also, the plant’s efficiency and increased productivity will be shown
by amperage numbers which do not max out on the motor and steadier plant
output even during times of poor fuel quality.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
N/A
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 158 of 309
KF - 2022 ID Fan & Motor Replacement
Business Case Justification Narrative Template Version: 04.21.2022 Page 4 of 9
1.5.2 For asset replacement, include graphical or narrative representation of metrics associated with the current condition of the asset that is proposed for replacement.
The graph above shows a typical instance of the plant ramping up to nearly full
load (MWs shown in purple) with the damper position maxing out (orange trend)
as the motor tops out in amperage (shown in blue). Once the amps on the motor plateau around 105 amps, the other parameters are forced to plateau as well.
This shows how the motor can be a limiting factor in the plant’s MW output.
The photos above show the kind of repairs that were necessary during the spring outage of 2021. There are extensive weld repairs on large sections of the
fan blades and plate metal additions to replace material that has been eroded
during the life of the fan. This kind of repair has been routine over the last several
years and is costly as it is very time-intensive work. The blades and periphery
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 159 of 309
KF - 2022 ID Fan & Motor Replacement
Business Case Justification Narrative Template Version: 04.21.2022 Page 5 of 9
continue to see deterioration each year. Ideally another major repair job (as
shown above) can be avoided before the fan is replaced.
2.PROPOSAL AND RECOMMENDED SOLUTION
The proposed solution involves replacing the ID fan and motor to appropriatelyaccommodate the needs of the plant. The proposed solution includes implementinga variable frequency drive (VFD) which addresses fluctuations in loads expected from
fuel moisture and the ability to operate in a flexible EIM market as well as being able
to pick up generation gaps which could result from the proposed plant addition. The
VFD also improves fan and motor efficiency during operations minimizing the wear
that has become an annual maintenance concern. Power consumption of the fan
motor will be minimized by having the VFD adjust the motor’s output. The change in
equipment will precipitate ducting changes and potential foundation modifications.
Option Capital Cost Start Complete
Replace the ID fan, motor and add VFD $1,650,000 10/2022 06/2024
Replace the ID fan and motor (no VFD) $1,150,000 10/2022 06/2024
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
The main data points which were considered in preparation of this capital
request are the limitations to plant performance and output which have been manifested in PI data and control room rounds sheets over the past several
years. This data will also allow tracking of improvement once the solution is
implemented. Although the problems have exhibited themselves for many more
years, this most recent data shows the immediacy of the issue and regularity of
limited operation. Maintenance and repair costs alone have pushed the need for these components to be replaced into the foreground. Both the concerns for
hampered generation and the concern about potential downtime due to asset
conditions have also been considered. In regard to determining whether to
implement a VFD into the system, the power savings achieved by replacing
dampers with a new drive and the pay-back period for this option make this solution desirable. Additionally, the VFD will be able to provide improved ability
to make up for potential losses in generation related to the plant upgrade and
flexibility of operation in unideal fuel conditions which provide additional power
consumption cost savings.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 160 of 309
KF - 2022 ID Fan & Motor Replacement
Business Case Justification Narrative Template Version: 04.21.2022 Page 6 of 9
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include any known or estimated reductions to O&M as a result of this investment.
The ID fan and motor replacement project will consist of a multi-year project with
the first year being the procurement of the fan, motor and VFD. Year two will
be the installation of these components as part of the annual Spring outage. The
year that these components are installed there will be no need for fan repair which will be reflected in reduced O&M costs.
A complete failure of the ID Fan could extend many weeks. The estimated
daily Power Supply outage cost for this facility is $69,700 (refer to 20220825
Thermal Daily Outage Cost Estimation Tool CONFIDENTIAL.xlsx).
2.3 Outline any business functions and processes that may be impacted (and how) by the business case for it to be successfully implemented.
This project will be managed within the normal spring annual outage. The VFD
will save on station power which will increase power out to our customers.
2.4 Discuss the alternatives that were considered and any tangible risks and mitigation strategies for each alternative.
One alternative is to let the assets run to failure. This is a risky option for several
reasons most notably the potential for unplanned plant downtime. It also would
result in increasing O&M costs in the coming years with the replacement still
required at the point of failure.
Another alternative is to not implement a VFD into the system and essentially just replace the components in kind with what is currently installed. This
alternative is viable but could present the plant with some of the issues which
are currently problematic such as limitations during poor fuel quality and wasted
energy consumption when dampers are heavily utilized. The VFD addresses
these issues making it a more desirable solution.
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
Procurement of components for this project will begin in mid-summer of 2023
due to long lead times on items such as the VFD and ID fan. Design
considerations and consulting have already begun with the fan and VFD supplier and these will continue up and through the point of purchase. The ID
fan, motor and VFD will all be installed during the annual spring outage
timeframe in 2024 and will be used and useful upon completion when the plant
comes back online following the outage.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 161 of 309
KF - 2022 ID Fan & Motor Replacement
Business Case Justification Narrative Template Version: 04.21.2022 Page 7 of 9
2.6 Discuss how the proposed investment aligns with strategic vision, goals, objectives and mission statement of the organization.
This project aligns with providing safe and reliable renewable energy for our
customers.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In addition, please explain how the investment prudency will be reviewed and re-evaluated throughout the project
This project invests into the long-term life of the plant and takes into
consideration modifications related to plant expansion. This solution resets the
clock on extensive fan repairs and increases the efficiency of the plant by
implementing new technology which will allow the plant to be more adaptable to varying fuel quality and generation setpoints. Although the plant has been able
to get along in the current state, it is not a sustainable solution and this work will
not only improve performance but provide minimize maintenance on these
components for decades due to technological advances in fan and drive design.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
Thermal Operations and Maintenance Manager
Plant Manager
Thermal Engineer
Kettle Falls Specialist
Supply Chain
2.8.2 Identify any related Business Cases
N/A
3.MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
Thermal and Operations Maintenance Manager
Plant Manager
GPSS Thermal Engineer
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 162 of 309
KF - 2022 ID Fan & Motor Replacement
Business Case Justification Narrative Template Version: 04.21.2022 Page 8 of 9
3.2 Provide and discuss the governance processes and people that will
provide oversight
The Plant Manager will work with the Thermal Engineer and/or Project Contract Engineering to manage the procurement, fabrication and installation of the ID fan, motor and VFD. Status reports and monthly update meetings will be made
to the Thermal Operations and Maintenance Manager up until the installation
process begins then weekly progress meetings will be used to keep the group
informed.
3.3 How will decision-making, prioritization, and change requests be documented and monitored
This project will utilize Corporate Supply Chain Contract Change Order process
for any changes to scope, schedule and budget changes. The project will follow
the GPSS Department Project Delivery process. Issues or concerns will be
brought to the GPSS Thermal Operations and Maintenance Manager for guidance and approval.
4.APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Kettle Falls ID Fan & Motor
Replacement Project and agree with the approach it presents. Significant changes to this will
be coordinated with and approved by the undersigned or their designated representatives.
Signature: Date: 8/24/2022
Print Name: Derek Babine
Title: Mechanical Engineer
Role: Business Case Owner
Signature: Date:
Print Name: Alexis Alexander
Title: Director of GPSS
Role: Business Case Sponsor
Signature: Date:
Print Name: Thomas Dempsey
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 163 of 309
KF - 2022 ID Fan & Motor Replacement
Business Case Justification Narrative Template Version: 04.21.2022 Page 9 of 9
Title: GPSS Thermal Ops & Maint. Mgr.
Role: Steering/Advisory Committee Review
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 164 of 309
Little Falls Crane Pad and Barge Landing
Business Case Justification Narrative Template Version: 04.21.2022 Page 1 of 6
EXECUTIVE SUMMARY
The existing crane pad/trash boom anchor at Little Falls are at their end of useful life. The sheet pile wall is
severely rusted and deteriorating in several locations including where it adjoins the river bottom. The
foundation is eroding to the point where if too much weight was put on the crane pad there could be complete
failure and equipment could fall into the forebay. The only way to currently use the crane pad is to adjust
outriggers far enough away from the water’s edge which causes partial obstruction to Spokane Indian Tribe’s
Martha Boardman Rd.

A new crane pad/barge landing/trashboom anchor system needs to be designed and constructed. This is a
critical path project to be prioritized as such to prepare future and safe access for the Little Falls Intake Project
(headgates, supporting structure, motors, and trash rake), as well as the Little Falls Controlled/Gated Spillway
Project to repair concrete and replace flashboard function on the spillway dam. The current off-loading and
staging causes obstruction and congestion to the road as well as the proximity to the roadway increases
safety hazards for workers and site personnel.

The Crane Pad and Barge Landing will cost approximately 4 million dollars to design, engineer, and construct.
This also includes demolition and removal of the existing crane pad and trash boom as well as environmental
protection and mitigation.

This project benefits Avista’s customers as the risk of continued use of the current crane pad could result in
failure… leading to potential loss of human life and/or serious injury, damage to property and equipment, and
lack of access to maintenance and construction projects.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 165 of 309
Little Falls Crane Pad and Barge Landing
Business Case Justification Narrative Template Version: 04.21.2022 Page 2 of 6
VERSION HISTORY
Version Author Description Date Notes
1.0 Mac Mikkelsen Executive Summary 05/31/2022
2.0 Mac Mikkelsen Draft 09/01/2022

GENERAL INFORMATION

1. BUSINESS PROBLEM
[This section must provide the overall business case information conveying the benefit to the customer, what the project will do and current problem statement]
Requested Spend Amount $3,000,000
Requested Spend Time Period 2 years
Requesting Organization/Department GPSS
Business Case Owner | Sponsor Mac Mikkelsen | Alexis Alexander
Sponsor Organization/Department GPSS
Phase Choose an item.
Category Choose an item.
Driver Choose an item.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 166 of 309
Little Falls Crane Pad and Barge Landing
Business Case Justification Narrative Template Version: 04.21.2022 Page 3 of 6
1.1 What is the current or potential problem that is being addressed? The
current crane pad is failing. There isn’t enough room to get off of the Spokane Indian Reservation Road to utilize the crane. The Trash Boom Anchor and Trash
Boom do not work correctly due to the configuration and need to be replaced.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer. The crane
pad will fail eventually, and it will be more expensive to fix than replace. It poses
a public and employee safety concern. A new crane pad, landing, trash boom
anchor, and trash boom will be much more efficient, safety for everyone, and
increase performance and reliability which will benefit our customers. This project is also critical to be able to complete futures projects at the intake and
spillway which will also provide customer service quality.

1.3 Identify why this work is needed now and what risks there are if not approved or is deferred. We need to replace the whole system as soon as
possible as the current system is failing. If we neglect these assets they will fail,
and we won’t be able to access our forebay for maintenance and future capital
projects. In the long run it will be more expensive, and the neglect may lead to a danger to the public, our employees and ultimately our customers.

1.4 Identify any measures that can be used to determine whether the investment would successfully deliver on the objectives and address the need listed above. A new crane pad, landing, trash boom anchor and trash
boom will provide a safer, more efficient system, and less likelihood of complete
failure based on the new condition.

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
Geotech work was completed in 2022 to show the stability of the ground if a new crane pad and landing were to be installed. The current pilings are rusted out and losing their foundational support and must be removed.
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for replacement. This is available in the GPSS library.
2. PROPOSAL AND RECOMMENDED SOLUTION
It is recommended that the Crane Pad, Landing, Trash Boom Anchor, and Trash Boom be fully replaced. The old ones have more than exceeded their useful life. A replacement of this entire system will better suit the needs of plant operations, reduce employee and public safety concerns, and provide longer resilience and use for future projects and maintenance.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 167 of 309
Little Falls Crane Pad and Barge Landing
Business Case Justification Narrative Template Version: 04.21.2022 Page 4 of 6
Option Capital Cost Start Complete
Replace Crane Pad, Landing, and Trash Boom
System
$3,000,000 06/2022 12/2023

2.1 Describe what metrics, data, analysis, or information was considered when preparing this capital request. - Better access to forebay - Safer conditions for employees and the public to be able to get off of a busy road (that is not Avista’s at the bottom of hill) - Reduction of maintenance and constantly adjusting the current trash boom as there will be a better design with the new - The current pilings are failing, and the loss of foundation may lead to employee safety concerns, public safety concerns, and environmental concerns
Reference key points from external documentation, list any addendums, attachments etc.

2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the expected functions, processes or deliverables that will result from the capital spend?). Include any known or estimated reductions to O&M as a result of this investment.
Thee investment will increase efficiency and reduced costs by providing a safer and more reliable landing to work from and manage the trash boom.

[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]

2.3 Outline any business functions and processes that may be impacted (and how) by the business case for it to be successfully implemented.
Construction on the new crane pad, landing, and trash boom system may cause some concerns for operations – specifically to the ability to generate electricity at Little Falls due to immediate proximity of the powerplant.

2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative. An upstream location for this was
discussed, but Avista doesn’t own the land where this could go as it’s on the Spokane Indian Reservation.

2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
Initial design began in July 2022 and construction will begin in 2023. The project and system will be become used and useful by 2024.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 168 of 309
Little Falls Crane Pad and Barge Landing
Business Case Justification Narrative Template Version: 04.21.2022 Page 5 of 6

2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives, and mission statement of the organization.
Replacing the crane pad, landing, and trash boom system is the responsible thing to do. It aligns with our mission as it sets us up to be able to provide reliable and affordable electricity to our customers.

2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In addition, please explain how the investment prudency will be reviewed and re-evaluated throughout the project It is an appropriate amount to
replace the asset and would be well worth the cost as the current asset is failing.

2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
GPSS Operations, GPSS Engineering and Dam Safety, GPSS Mechanic Shop, Electric
Shop, and Relay Shop, Telecom Shop, Environmental Affairs, Power Supply, Energy Resources, System Operations
2.8.2 Identify any related Business Cases
[Including any business cases that may have been replaced by this business case]

3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
Manager of Hydro Operations, Director of GPSS, Manager of MS and Electric Shop, Manager of Civil and Mechanical Engineering

3.2 Provide and discuss the governance processes and people that will provide oversight

3.3 How will decision-making, prioritization, and change requests be
documented and monitored

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 169 of 309
Little Falls Crane Pad and Barge Landing
Business Case Justification Narrative Template Version: 04.21.2022 Page 6 of 6
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Little Falls Crane Pad and Barge
Landing and agree with the approach it presents. Significant changes to this will be coordinated with and approved by the undersigned or their designated representatives.

Date:
Mac Mikkelsen
Manager Hydro Ops
Business Case Owner

Date:
Alexis Alexander
GPSS Director
Business Case Sponsor

Date:

Steering/Advisory Committee Review

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 170 of 309
 


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Schedule 4, Page 171 of 309
 


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Schedule 4, Page 172 of 309
 


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Schedule 4, Page 173 of 309
 


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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 174 of 309
 


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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 175 of 309
 


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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 176 of 309
 


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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 177 of 309
Long Lake Plant Upgrade
Business Case Justification Narrative Page 1 of {

EXECUTIVE SUMMARY
The Long Lake Plant Upgrade is a series of several capital project improvements
built into a larger Capital Program. The program includes a full plant condition
assessment, replacement of all Generating Units, Generator Step-up Transformers (GSUs), Station Service, and many of the mechanical, electrical, and controls
systems and equipment have met their end of useful life. This equipment needs to
be replaced in order to continue to operate efficiently and provide generation needs
to Avista’s customers.
Long Lake serves Avista’s allocated north electric district providing power to our
transmission grid and local distribution power sources. The primary drivers for the
Long Lake Plant Upgrade are Performance & Capacity, Asset Condition, and Failed
Plant & Operations. Four alternatives were considered for solutions to replacing the
aged and failing equipment; (1) Install four new 30MW vertical units, (2) Construct a new one-unit powerhouse, (3) Construct a new two-unit powerhouse, and (4)
Alternative 4 and the recommended alternative, replace the existing units in kind. An
anticipated program budget of $85M has been developed.
Upgrading our Long Lake Plant will enable our generation fleet to continue to provide safe and reliable power to our customers. If not approved, The Long Lake powerhouse would continue to operate as it has for the past 10 years. O&M costs
would continue to rise. In an additional 10 years, if the trend continues, average
O&M costs will rise. Due to the condition of the generators, it is likely that one of
the generators or another piece of major equipment will fail and permanently disable equipment, increasing forced outage numbers. For example, in December of 2021 GSU 4 was replaced due to its dangerously high gas levels. This was a
cost of $280k, and fortunately we had a spare otherwise the unit would still be out
of service.
The Plant Upgrade began in 2017 and will continue until estimated completion in December 2029.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 178 of 309
Long Lake Plant Upgrade
Business Case Justification Narrative Template Version: 04.21.2022 Page 2 of 10
VERSION HISTORY
Version Author Description Date Notes
1.0 Steve Wenke Initial Request 04/10/2017 This was on the old template
2.0 Mac Mikkelsen Revised 09/02/2022 Transferred to new version

GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
The existing equipment ranges in age from 20 to more than 100 years old.
We have experienced an increase in forced outages at Long Lake over the
past several years, almost zero in 2011 and increasing every year since then. This is caused by equipment failures on several different pieces of
equipment. Specifically, the turbines are thrusting too much (a sign of
significant wear), including a failure in 2015. The 1990 vintage control system
is failing, and only secondary markets can support this equipment.
The original generators consist of a stator frame, stator core, stator winding, and rotor field poles. They were originally rated at 12 MW's. In the late
1940's, the height of the dam was raised 16 feet which resulted in more
operating head for the generating units. A forced air-cooling system for the
generators was added to the plant at that time to accommodate the increase
in output from 12 to 17 MW's due to the increased head. In the 1960's, the stator windings on all the units were replaced and the rating of the
generators, along with the forced air system allowed for the units to operate
at the higher 17 MW output.
Requested Spend Amount $85,000,000
Requested Spend Time Period 12 years
Requesting Organization/Department GPSS
Business Case Owner | Sponsor Mac Mikkelsen | Alexis Alexander
Sponsor Organization/Department GPSS
Phase Execution
Category Program
Driver Asset Condition
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 179 of 309
Long Lake Plant Upgrade
Business Case Justification Narrative Template Version: 04.21.2022 Page 3 of 10
In the 1990's, the original turbine runners were replaced and upgraded. The
improvement in turbine runner efficiency resulted in still another increase in unit output. Since the mid-1990's, the generators have been operating with a
maximum output of 22 to 24 MW's. The generators are currently operated at
their maximum temperature which stresses the life cycle of the already 50+-
year-old winding.
Inspections of other components of the generator show the stator core is "wavy". The core lamination steel should be in straight. The "wave" pattern is
a strong indication of higher-than-expected losses are occurring in the
generator. Finally, maintenance reports have identified that the field poles on
the rotor have shifted from their designed position very slightly over the
years. While there can be several causes of this movement, it is speculated that it is due to the high operating temperatures of the generator. This
highlights the first driver for the program, reliability.
With the increase in generator output, the output of the GSU has also
increased to its rating. These GSU's are now running at the high 65C
temperature which is a concern. As these GSU's are more than 30 years old and operating at the high end of their design temperature, these are now
approaching their end of useful life and need to be replaced proactively
rather than wait for a failure.
The other major driver for the program is safety. The switching procedure for
moving station service from one generator to the other resulted in a lost time accident and a near miss in the past 5 years. In addition, the station service
disconnects represent the greatest arc-flash potential in the company. This
area is roped off and substantial safety equipment is required to operate the
disconnects. This project will reconfigure this system to eliminate requiring
personnel to perform this operation and avoid the arc-flash potential area.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer. Much of
the plant and its components are aged to the point of failure and/or have become obsolete. The Long Lake HED is a critical asset needed for generation of clean
renewable energy. The consistent and reliable operation of the generating units
and related equipment is needed to be able to confirm generation, distribution,
and transmission of electricity to our customers. The equipment is also essential
to recreation, environmental protection, dam, and public safety. These all benefit the customer by increasing efficiency and safety in performance.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 180 of 309
Long Lake Plant Upgrade
Business Case Justification Narrative Template Version: 04.21.2022 Page 4 of 10
1.3 Identify why this work is needed now and what risks there are if not approved or is deferred. The equipment needs to be upgraded for continued reliability as soon as possible. The risks of deferment may result in the lack of
the ability to generate hydroelectricity and provide our commitment to the BES,
and EIM. Deferment will also lead to increased O&M costs. The Long Lake
powerhouse would continue to operate as it has for the past 10 years. O&M
costs would continue to rise. In an additional 10 years, if the trend continues, average O&M costs will rise from $285k in 2005 to $590 in 2014 and projected
to be $900k in 2024. Due to the condition of the generators, it is likely that one
of the generators or another piece of major equipment will fail and permanently
disable equipment, increasing forced outage numbers.

1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above. The LLPU project team will be utilizing data from GPSS
asset condition information, trending plant data, as well as, using third party engineering experts to assist in alternative analysis, and engineering
recommendations for upgrades. Third party studies have helped identify large
scale options for the plant upgrade, and internal Avista engineering in
partnership with third party consultants have added additional alternatives for
consideration. Alternative analysis options are considering upfront costs, construction costs, life cycle costs, return of investment, and sustained
maintenance costs, along with future capacity options.

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
• Summary of Investment Considerations for Long Lake Modernization Program
• Spokane River Assessment (Oct 2014) Phase II Reconnaissance Study – Long Lake HED – URS
• Long Lake Dam Generator Voltage Study & Life Cycle Analysis (June 2020) - Stantec
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 181 of 309
Long Lake Plant Upgrade
Business Case Justification Narrative Template Version: 04.21.2022 Page 5 of 10
1.5.2 For asset replacement, include graphical or narrative representation of metrics associated with the current condition of the assets that is proposed for replacement.
Below is a graph of Forced Outage Factor for Long Lake HED from Avista's Asset Management Plan.

The below graph shows the O&M cost at Long Lake for years 2005 - 2015. The trendline
is increasing due to increasing repairs to aging equipment.

2. PROPOSAL AND RECOMMENDED SOLUTION
It Alternative 4 and Recommended Alternative: Replace Units In-Kind would replace the existing major unit equipment (generator, field poles, governors, exciters, generator
0%
5%
10%
15%
20%
25%
30%
35%
2009 2010 2011 2012 2013 2014 2015
Long Lake HED Forced Outage Factor
Long Lake HED Unit 1 Long Lake HED Unit 2
Long Lake HED Unit 3 Long Lake HED Unit 4
0.0522 GADS benchmark for
29MW & smaller hydro units
0
100,000
200,000
300,000
400,000
500,000
600,000
700,000
800,000
900,000
1,000,000
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
O&M Cost at Long Lake
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 182 of 309
Long Lake Plant Upgrade
Business Case Justification Narrative Template Version: 04.21.2022 Page 6 of 10
breakers) with new equipment.

2.1 Describe what metrics, data, analysis, or information was considered
when preparing this capital request.
Relevant data is comprised of Long Lake HED historical data, maintenance logs, asset condition, third party analysis, and lessons learned from similar work performed at Little
Falls HED

2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e., what are the expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M because of this investment.
Over the course of 11 years, the average O&M spend at Long Lake was $470k, with the low being $262k and the high year being $944k. In addition, the O&M cost is
trending upward. After the upgrade, the expected O&M cost is $200k/year, an average
reduction of $270k/year.

[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy Statement), therefore it is critical that these impacts are thought through to support rate recovery.]

Option Capital
Cost
Requested
Start
Requested
Complete
Do nothing $0 N/A
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 183 of 309
Long Lake Plant Upgrade
Business Case Justification Narrative Template Version: 04.21.2022 Page 7 of 10
2.3 Outline any business functions and processes that may be impacted (and how) by the business case for it to be successfully implemented.
The respective projects teams are working with many other business units and very high level of coordination will be ongoing throughout the life of LLPU. Representative
business units are as follows, but not limited to; Substation, Transmission, Protection, System Operations, Power Supply, Supply Chain, Environmental & Permitting, Dam
Safety, GPSS Engineering, GPSS Project Delivery, GPSS Shops, Corporate
Communications, Facilities, Distribution Operations, State and Local Agencies, and external contractors and engineering consultants. There will undoubtedly be impacts to
operations, system operations, environmental, power supply, and others previously
mentioned throughout several phased of project implementation.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Do Nothing: Continue to run plant and repair as necessary
The Long Lake powerhouse would continue to operate as it has for the past 10 years. O&M costs would continue to rise. In an additional 10 years, if the trend continues,
average O&M costs will rise from $285k in 2005 to $590 in 2014 and projected to be $900k in 2024. Due to the condition of the generators, it is likely that one of the generators or another piece of major equipment will fail and permanently disable
equipment, increasing forced outage numbers.
Alternative 1: Install four new 30MW vertical units
This alternative would be to replace the four existing units in the powerhouse with four
new 30 MW Kaplan units. Significant civil, electrical, and mechanical work would be required, in addition to powerhouse access.
The increased yearly generation would be 114,000MWh. Using $30/MWh (extremely
conservative number) the rough yearly benefit to Avista is $3.4M. The payoff period is greater than 30 years and therefore this alternative was abandoned.
Alternative 2: Construct one unit powerhouse
Instead of upgrading the current powerhouse, this alternative is to construct a new powerhouse with a single, 68MW next to the existing powerhouse, using the saddle
dam (also referred to as the “arch dam”) as an intake. This alternative would only use
the old powerhouse during high flows, when flows exceeded the new unit’s capacity. Additional funds would be required to upgrade, even at a minimum level, to address
some of the failing components.
The increased yearly generation would be 170,000MWh. Again, using $30/MWh the rough yearly benefit to Avista is $5.1M. The payoff for this is 30 years. Again, since
this cost does not include the additional work required in the plant and the cost of the risk associated with modifying the saddle dam, this alternative was abandoned.
Alternative 3: Construct two-unit powerhouse
Another option to build a new powerhouse is to construct a new powerhouse with two, 76MW units next to the existing powerhouse. This alternative would also use the
saddle dam as an intake. This alternative would only use the old powerhouse during
extreme high flows, minimizing the need to perform any upgrades to the old plant.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 184 of 309
Long Lake Plant Upgrade
Business Case Justification Narrative Template Version: 04.21.2022 Page 8 of 10
The increased yearly generation would be 258,000MWh. Using $30MWh, the rough yearly benefit to Avista is $7.7M. The payoff would be greater than 30 years and therefore the alternative was abandoned.
Alternative 4 and Recommended Alternative: Replace units in-kind
This alternative would replace the existing major unit equipment (generator, field poles, governors, exciters, generator breakers) with new equipment.
Over the past 11 years, the average O&M spend at Long Lake was $470k, with the low being $262k and the high year being $944k. In addition, the O&M cost is trending
upward. After the upgrade, the expected O&M cost is $200k/year, an average
reduction of $270k/year.

2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
May 2017 – Project Kickoff September 2018 – Bridge Crane Replacement - Complete
September 2018 – Sewer System Overhaul - Complete
September 2018 – Access Road Overhaul - Complete January 2020 – Facilities Upgrades Phase 1 - Complete
August 2023 - Station Service Replacement 1
August2023 – GSU Upgrade Phase 1 August 2023 – First Unit Upgrade
November 2025 – Second Unit Upgrade
December 2026 - Station Service Replacement 2 December 2026 – GSU Upgrade Phase 2
December 2026 – Third Unit Upgrade February 2026 – Facilities Upgrade Phase 2 December 2027 – Fourth Unit Upgrade
2.6 Discuss how the proposed investment aligns with strategic vision, goals, objectives, and mission statement of the organization.
The Long Lake Plant Upgrade aligns with the Safe and Reliable Infrastructure
company strategy. The program will address safety and reliability issues while
looking for innovative, economical ways to deliver the projects.
2.7 Include why the requested amount above is considered a prudent investment, providing, or attaching any supporting documentation. In addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project.
The project budget and total cost will be regularly reviewed with the project
steering committee, as well as receive approvals as described below for any
changes in scope and cost. Prudency is also measured by remaining in compliance the FERC License such that we can continue to operate Spokane
River dams for the benefit of our customers and company.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 185 of 309
Long Lake Plant Upgrade
Business Case Justification Narrative Template Version: 04.21.2022 Page 9 of 10
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
GPSS Director, Director of Power Supply, Director Environmental Affairs, Spokane
River License Manger, Manager of Hydro Operations and Maintenance, Lower Spokane River Manager, Manager of Maintenance Management & Construction,
Project Delivery Manager, GPSS Engineering and Dam Safety, GPSS Mechanic
Shop, Electric Shop, and Relay Shop, Telecom Shop, Energy Resources, System Operations

2.8.2 Identify any related Business Cases
n/a

3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
This program is comprised of two layers of Steering Committee Oversight. One layer
of oversight is at the program level and the other layer is at the project level.
The Program Steering Committee is responsible for vetting and approving the objective, scope, and priority of the program. The deliverables for the program are then reviewed
with the Program Steering Committee on a semi-annual basis. Any significant changes
to the program’s scope, budget or schedule will be approved by the Program Steering Committee. The Program Steering Committee is composed of the Director of GPSS,
Director of Environmental Affairs, and the Director of Power Supply. This committee meets semi-annually, or as major events create a change order request.
The Project Steering Committee oversees the deliverables of the individual projects.
Each member of the steering committee represents a major stakeholder in the project. The members are dependent on the respective project but will include representatives
from hydro operations, central shops, and engineering. The Project Steering
Committee will approve and changes to the schedule, scope, and budget of the individual project. They also are responsible for approving the necessary personnel for the completion of the project. This group is engaged on a quarterly basis.
3.2 How will decision-making, prioritization, and change requests be documented and monitored
The Project Steering Committee oversees the deliverables of the individual projects.
Each member of the steering committee represents a major stakeholder in the project.
The members are dependent on the respective project but will include representatives from hydro operations, central shops, and engineering. The Project Steering
Committee will approve and changes to the schedule, scope, and budget of the
individual project. They also are responsible for approving the necessary personnel for the completion of the project. This group is engaged on a quarterly basis.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 186 of 309
Long Lake Plant Upgrade
Business Case Justification Narrative Template Version: 04.21.2022 Page 10 of 10
3.3 How will decision-making, prioritization, and change requests be documented and monitored
Generally decision-making, and prioritization will be done through Steering Committee and GPSS Department SCRUM. Projects will be utilizing the Project Change Log to
track and manage all Project Change Requests (PCR) associated with the delivery of the construction project. The PCR describes the need for change, supplemental
documentation, related project artifacts, change order proposals, and any other
pertinent information. PCRs are then signed for approval by the project approval thresholds, and then processed against the project risk registry, and or contract
amendment with the contractor.

4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Long Lake Plant Upgrade Project and agree with the approach it presents. Significant changes to this will be
coordinated with and approved by the undersigned or their designated representatives.

Date:
Mac Mikkelsen
Manager Hydro Ops
Business Case Owner

Date:
Alexis Alexander
GPSS Director
Business Case Sponsor

Date:

Steering/Advisory Committee Review

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 187 of 309
Monroe St Abandoned Penstock Stabilization
Business Case Justification Narrative Page 1 of 8
EXECUTIVE SUMMARY

The Monroe Street Powerhouse was initially constructed in 1890 and has undergone
several modernizations over the last 129 years. During the 1972 modernization, three of the original penstock intakes were plugged with concrete and sealed with a layer of shot-
crete. The three 10 ft. diameter steel penstocks were only partially removed, leaving an
approximate 250 ft. length of each buried under what is now Huntington Park. It is
unknown if the penstocks were also backfilled with material, posing a risk of implosion.
These penstocks run underneath parts of the access road, crane staging area, and walking path through the park. The park is open to the public, and the access road and
crane areas are critical to maintaining the safe and efficient operation of the Monroe Street
Hydroelectric Development. During the 2018 Maintenance Assessment, these penstocks
were identified as a high risk due to their location, unknown condition, and observed
groundwater.
The recommended solution includes further investigation of the intake dam and penstocks
to better quantify the risk, and implementation a plan to mitigate those risks. The scope
of this work would likely include an initial engineering evaluation, including investigatory
drilling, with stabilization efforts likely to include grouting of the intake and penstock.
The estimated cost of the project is $760,000. The service code for this program is
Electric Direct and the jurisdiction for the project is Allocated North serving our electric
customers in Washington and Idaho. Operating Monroe Street safely and reliably
provides our customers with low cost, reliable power while ensuring the region has the resources it needs for the Bulk Electric System (BES).

VERSION HISTORY
Version Author Description Date Notes
Draft Ryan Bean Initial draft of original business case 6/21/2019
1.0 Ryan Bean Updated Approval Status 7/2/2019 Full amount approved
2.0 Ryan Bean 5 Year Planning 2020 & New Form 7/8/2020
3.0 Ryan Bean 2022 Annual Refresh 8/18/2022 Reclassified Drilling
costs to O&M

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 188 of 309
Monroe St Abandoned Penstock Stabilization
Business Case Justification Narrative Page 2 of 8
GENERAL INFORMATION

1. BUSINESS PROBLEM

1.1 What is the current or potential problem that is being addressed?
The Monroe Street Powerhouse was initially constructed in 1890 and has
undergone several modernizations over the last 129 years. During the 1972
modernization, a new turbine intake and penstock arrangement was installed,
just prior to Expo ’74. During this upgrade, three of the original penstock intakes were plugged with concrete and sealed with a layer of shot-crete. The three 10 ft. diameter steel penstocks were only partially removed, leaving an approximate
250 ft. length of each buried on site. It is unknown if the penstocks were
backfilled with material, posing a risk of implosion. The penstocks are located
under what is now Huntington Park and run underneath parts of the access road, crane staging area, and walking path through the park.

1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer.
The driver for this business case is Failed Plant. The original penstocks are no
longer functional and pose a risk to the continued operation of the park and the
power plant. Monroe Street supplies year-round base load hydroelectric power
to Avista’s portfolio. Continuing to operate Monroe Street safely and reliably provides our customers with low cost, reliable power while ensuring the region
has the resources it needs for the Bulk Electric System (BES).

Requested Spend Amount $760,000
Requested Spend Time Period 2 years
Requesting Organization/Department C07/GPSS
Business Case Owner | Sponsor Ryan Bean | Alexis Alexander
Sponsor Organization/Department C07/GPSS
Phase Initiation
Category Project
Driver Failed Plant & Operations
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 189 of 309
Monroe St Abandoned Penstock Stabilization
Business Case Justification Narrative Page 3 of 8
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
The penstocks are located under what is now Huntington Park and run underneath parts of the access road, crane staging area, and walking path through the park. The park is open to the public, and the access road and crane
areas are critical to maintaining the safe and efficient operation of the Monroe
Street Hydroelectric Development. During the 2018 Maintenance Assessment,
these penstocks were identified as a high risk due to their location, unknown condition, and observed groundwater. Due to the unknown condition of these penstocks, there is a risk of implosion of the abandoned penstocks due to
deterioration, potentially resulting in an uncontrolled release of water thereby
jeopardizing the plant and the park.

1.4 Identify any measures that can be used to determine whether the investment would successfully deliver on the objectives and address the
need listed above.
The investment would field effort in two phases. The first phase would consist
of an investigation of the penstocks and original intake dam to determine the condition. The second phase would implement corrective actions to eliminate the risk from implosion and ensure the intake structure is watertight and fit for
continued service. The measure of success would be the stabilization of the
above components resulting in the mitigation of risk to the public and continued
production at the plant.

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem.
See project documentation from 2016 storm water controls and
investigation.
1.5.2 For asset replacement, include graphical or narrative representation
of metrics associated with the current condition of the asset that is proposed for replacement.
The metric supporting the stabilization of the current system is that it is no longer useful and poses a risk to continued operation of the park and plant.
During the 2018 Maintenance Assessment, these penstocks were
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 190 of 309
Monroe St Abandoned Penstock Stabilization
Business Case Justification Narrative Page 4 of 8
identified as a high risk due to their location, unknown condition, and
observed groundwater.

Option Capital Cost Start Complete
Investigate to ascertain condition; and
mitigate leakage or instability if needed.
$760,000 01 2022 12 2023
Continue to operate at risk. $0 01 2021

2.1 Describe what metrics, data, analysis or information was considered when preparing this capital request.

The failure of the system and risk to the plant is the primary metric for justification
of the project. A significant increase in ground water was observed in
Huntington Park in 2007 when groundwater was observed to be traveling
through the 13.8 kV underground electric vault and into the powerhouse, requiring remediation at the electric vault. Since 2007, excessive groundwater
persisted to leak into the powerhouse through cracks in the concrete, and
underground conduit penetrations, requiring constant monitoring and controls to
be installed to manage the water. In 2015 excessive groundwater was observed
to be flooding portions of Huntington Park, requiring areas of the park to be restricted for use. The flooding in Huntington Park increased by a magnitude
again in 2016, requiring additional storm water controls and investigation into
the source which was determined to be strongly associated with the buried
penstocks, validating the drawings indicating the presence of the buried
penstocks and associated infrastructure.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 191 of 309
Monroe St Abandoned Penstock Stabilization
Business Case Justification Narrative Page 5 of 8
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include any known or estimated reductions to O&M as a result of this investment.

The capital cost will be spread out over two years. The first year will be primarily
engineering, investigatory drilling, and determination of needed remediation.
This is estimated to be $150,000 and primarily O&M. The second year will include contractor mobilization and execution of the remediation plan. This is estimated to be $750,000. This will not offset significant O&M charges because
the equipment is no longer in service, so it is no longer maintained.

2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.

The execution of this project will temporarily inhibit access to the park and power
plant due to investigatory and remediation efforts. The outcome of this project will also answer questions about loading of the access road that would impact
future rehabs of the plant.

2.4 Discuss the alternatives that were considered and any tangible risks and mitigation strategies for each alternative.
Continue to Operate at risk.: The level of risk is unknown due to the condition
of the penstocks being unknown. However, the risk is likely to increase over
time due to deterioration of the penstocks and the presence of groundwater in
the park. Given the risk to the public, plant operations, and the company’s
reputation; doing nothing is not advisable.
Investigate and Remediate: This alternative includes further investigation of the
intake dam and penstocks to better quantify the risk, and implementation a plan
to mitigate those risks. The approach to fix is likely to involve grouting for
penstock and intake stabilization, as well as measures for additional water
management and monitoring. This alternative would provide a lasting solution to the above concerns and prevent future issues with access and safety.

2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
spend, and transfers to plant by year.

This project is expected to take two years. The effort in the first year will be
devoted investigation and design. The effort in the second year will consist of
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 192 of 309
Monroe St Abandoned Penstock Stabilization
Business Case Justification Narrative Page 6 of 8
execution of a remediation plan. The transfer to plant will be at the end of the
second year with the completion of the work.

2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.

Operating Monroe Street safely and reliably provides our customers with low cost, reliable power while ensuring the region has the resources it needs for the Bulk Electric System (BES). By taking care of this plant we support our mission
of improving our customer’s lives through innovative energy solutions which
includes hydroelectric generation. By executing this project, we ensure that
Monroe Street will continue to provide reliable service and mitigate risk to the
park and Avista’s reputation.

2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In addition, please explain how the investment prudency will be reviewed and re-evaluated throughout the project
The impacts due to an implosion could harm Avista employees, the public,
continued generation from the powerhouse, and Avista’s reputation.
A formal Project Manager will be assigned to a project of this size. The project will be managed within project management practices adopted by the Generation Production and Substation Support (GPSS) department. This
includes the creation of a Steering Committee and a formal Project Team. Once
the project is initiated, reporting on scope, schedule and cost will occur monthly.
Changes in scope, schedule, or cost will be surfaced by the Project Manager to the Steering Committee for governance. The Project Manager will manage the project through its conclusion.

2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
The primary stakeholders for this project are, the Hydro Regional Manager
on the Upper Spokane, the Upper Spokane plant personnel, GPSS
Engineering, Environmental Resources, the City of Spokane and Parks. Other stakeholders may be identified during project initiation.

2.8.2 Identify any related Business Cases
This project will need to be completed prior to any substantial rehab at the
Monroe Street power plant, however this is not anticipated to be needed for some time.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 193 of 309
Monroe St Abandoned Penstock Stabilization
Business Case Justification Narrative Page 7 of 8
3.1 Steering Committee or Advisory Group Information
A formal Project Manager will be assigned to a project of this size. The project
will be managed within project management practices adopted by the Generation Production and Substation Support (GPSS) department. A Steering Committee will be formed for this project. The Project Manager will manage the
project through its conclusion.
3.2 Provide and discuss the governance processes and people that will
provide oversight
Management of this project will include the creation of a Steering Committee which will include managers representing the key stakeholders involved in this
project. The project will also be executed by a formal Project Team lead by the
Project Manager.
3.3 How will decision-making, prioritization, and change requests be documented and monitored
Once the project is initiated, reporting on scope, schedule and cost will occur
monthly. Changes in scope, schedule, or cost will be surfaced by the Project
Manager to the Steering Committee for governance.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 194 of 309
Monroe St Abandoned Penstock Stabilization
Business Case Justification Narrative Page 8 of 8
The undersigned acknowledge they have reviewed the Monroe Street Abandoned Penstock Stabilization business case and agree with the approach it
presents. Significant changes to this will be coordinated with and approved by the undersigned or their designated representatives.
Business Case Owner
Business Case Sponsor
Steering/Advisory Committee Review
Template Version: 05/28/2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 195 of 309
Nine Mile Battery Building
Business Case Justification Narrative Template Version: 08/04/2020 Page 1 of 9
EXECUTIVE SUMMARY
The purpose of this project is to build a battery storage building for the batteries supplying
the Nine Mile Falls HED’s critical power system to improve reliability and safety. The battery room will be located near the switchyard and underground conduit will be installed to the powerhouse containing power and control cables. During emergency situations,
the critical power system is required to continually monitor and control the turbine
generators and spillway for safe operations of the river and its flow. The 125 VDC battery
banks are the most essential component of the critical power system and the health of the batteries needs to be closely monitored. The existing location batteries on the switchgear floor is susceptible to extreme temperatures that greatly reduce the reliability
and performance of the system. The location of the batteries is a safety issue, because
they contain hazardous material and expel potentially explosive hydrogen gases during
discharge. In addition to the reliability and safety concerns, the structural integrity of the existing floor needs to be reinforced as equipment is added or replaced. A new building with climate control and hydrogen monitoring dedicated to battery storage will greatly
enhance the critical power system reliability and eliminate unnecessary safety hazards.

The initial design of the powerhouse has begun as part of the Generation DC Supplied Upgrade program, but the estimated costs are too high to be funded through the program. Therefore, a separate business case is required to complete the design and construction
by the end of 2022 before major overhauls to the Units 3 and 4 begin.

VERSION HISTORY
Version Author Description Date Notes
1.0 Terri Echegoyen
Jeremy Winkle Original submission June 2021

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 196 of 309
Nine Mile Battery Building
Business Case Justification Narrative Template Version: 08/04/2020 Page 2 of 9

GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
There are a number of issues with the existing location of the batteries in the Nine Mile
HED powerhouse including:

• Excessive battery temperature – The batteries are open to the
switchgear floor and not enclosed in a climate controlled room.
Temperatures above 78 degrees Fahrenheit significantly reduces the usable life and performance of the batteries.
• Hydrogen danger - Batteries emit hydrogen gassing which is extremely
explosive in a concentrated area. The existing location of the batteries does not meet current safety standards to monitor and expel potentially explosive hydrogen gases.
• Switchgear floor loading concerns - The existing location of the batteries
on the switchgear floor may not be strong enough to safely store new batteries and equipment. During the Units 1 and 2 upgrade, the portions of the switchgear floor had to be strengthened prior to installing new
equipment. A thorough structural analysis would need to be completed
before installing new critical power equipment in the existing location.
• Battery transportation safety - Batteries contain corrosive acid and great care must be taken when installing and maintaining lead acid batteries.
The existing location requires transporting battery up and down multiple
levels of the powerhouse and creates safety hazard for electricians and
plant personnel.

Requested Spend Amount $800,000
Requested Spend Time Period 1 year - 2022
Requesting Organization/Department GPSS
Business Case Owner | Sponsor Jeremy Winkle | Andy Vickers
Sponsor Organization/Department GPSS
Phase Planning
Category Project
Driver Asset Condition
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 197 of 309
Nine Mile Battery Building
Business Case Justification Narrative Template Version: 08/04/2020 Page 3 of 9
1.2 Discuss the major drivers of the business case and the benefits to the customer.
During a utility power failure, the Nine Mile Falls HED facility’s critical power
system supplies emergency DC power to protect plant equipment and
personnel and AC power to control and monitor the generators and auxiliary
systems
These systems allow plant operations, during emergency situations, to continue to monitor and control the turbine generators and spillway for safe
operations of the river and its flow. Failure of this system during an emergency
situation could result in compromised safe operations, cause equipment failure
and extended outages. A reliable and safely maintained critical power system
benefits the customer by ensuring reliable operations and public safety during an emergency situation.

1.3 Identify why this work is needed now and what risks there are if not approved or is deferred
The battery banks are currently located in areas not designed for the storage or
operation of batteries, both because of the climate and the floor system. Battery
operation and life are hindered by being stored in a location whose temperatures
are outside of the recommended range. As isolated systems, when one system experiences a component failure, the remaining battery banks do not have the
ability to support the plant. The batteries have an expected life span of 20 years.
Excessive temperature above 78 degrees greatly reduces the expected life
span of the batteries and hinders performance. Construction of a dedicated
battery building similar to that constructed at Cabinet Gorge HED will provide an enclosed space thereby allowing for necessary climate control, monitoring and
safe operations.

If this program is not funded or deferred, there will be increasingly negative
impacts to the critical power system and continued safety concerns. As the batteries are exposed to high temperatures, their expected lifetime decreases
and requires replacement before failure. Emergent replacement of the batteries
may cause unplanned outages and strain resources to procure and install new
batteries. Since the integrity of the floor is questionable, a detailed analysis and possible improvement would need to be complete before installing new batteries delaying the installation. It would be very likely, the plant would need to operate
on a temporary battery system with limited capacity for an extended period of
time before replacement negatively impacting operational reliability. The safety
concerns associated with hazardous materials, hydrogen gassing, and structural integrity would continue to exist and expose plant personnel to dangers. Funding this business case will eliminate the operational and safety
concerns associated with location of the batteries.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 198 of 309
Nine Mile Battery Building
Business Case Justification Narrative Template Version: 08/04/2020 Page 4 of 9

1.4 Identify any measures that can be used to determine whether the investment would successfully deliver on the objectives and address the
need listed above.
Success will be measured through consistent monitoring of the batteries and
their environment. In the event of an emergency, the batteries would perform as
expected. Load tests would indicate that the expected life span of the batteries is consistent with manufactures specifications.

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
• Battery Temperature Data - Temperature monitoring in 2012 confirmed
prolong temperature near or above 85 degrees Fahrenheit.

Figure 1-2012 Battery Temperature Monitoring

• Switchgear temperatures are monitored on the PI Historian system.
During the late June 2021 heat wave, temperature in the powerhouse reached over 100 degrees Fahrenheit on multiple days. Daily
operational logs taken in the morning matched PI Historian temperature
of greater than 85 degrees Fahrenheit.
1.5.2 For asset replacement, include graphical or narrative representation of metrics associated with the current condition of the asset that is proposed for
replacement.
N/A
2. PROPOSAL AND RECOMMENDED SOLUTION

Option Capital Cost Start Complete
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 199 of 309
Nine Mile Battery Building
Business Case Justification Narrative Template Version: 08/04/2020 Page 5 of 9
[Recommended Solution] Dedicated Battery
Building
$800,000 01/2022 12/2022
[Alternative #1] Enclose batteries in existing
location
$950,000 01/2022 12/2022
[Alternative #2] Relocate batteries to plant
basement
$800,000 01/2022 12/2022
The recommend solution is to construct a dedicated battery building near the switchyard. This is the safest solution, because the hazards associated with
batteries will no longer be locates in the plant powerhouse.

2.1 Describe what metrics, data, analysis or information was considered when preparing this capital request. Analysis of the various options took into consideration overall cost, performance projections, ergonomic conditions, heat dissipation, hydrogen dissipation and
safety considerations. See attached document for details regarding alternative
methods analysis.
2.2 Discuss how the requested capital cost amount will be spent in the current year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
Project engineering will continue through 2021. A project within the Generation
DC Supplied System Update program already exists (20505079) and will support this work in 2021 with the goal being to solidify designs to be implemented in 2022.
The outcome of this investment is not expected to increase O&M costs. The
investment will reduce O&M costs for battery maintenance costs. The new
building will greatly reduce the risk of replacing one or multiple batteries.

2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
The negative safety impacts associated with the current locations of the batteries on plant operations will be eliminated after the successful
implementation of this business case. The major safety hazards will be isolated
to the dedicated battery room which will be closely monitored and only
accessible to necessary personnel. The impact to the operation team will be very positive.
The project will significantly benefit the crew performing battery maintenance.
The new battery room will be in a very accessible location to reduce
maintenance time. The room will be designed ergonomically to reduce the
impact on personnel maintaining and replacing batteries.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 200 of 309
Nine Mile Battery Building
Business Case Justification Narrative Template Version: 08/04/2020 Page 6 of 9
2.4 Discuss the alternatives that were considered and any tangible risks and mitigation strategies for each alternative.
Alternatives #1 and #2 were eliminated as acceptable solution, because the
batteries would still be located in the powerhouse and require disruptive
construction in the powerhouse. These solutions would require extended time
on temporary critical power. Most importantly, these solutions do not solve the
safety risk specifically maintaining the batteries in the powerhouse.
Please see the attached document for additional alternatives analysis
information.

2.5 Include a timeline of when this work will be started and completed. Describe when the investments become used and useful to the customer.

2.6 Discuss how the proposed investment aligns with strategic vision, goals, objectives and mission statement of the organization.
At Avista, our Mission is to improve our customers’ lives through innovative energy solutions – safely, responsibly and affordably. This project will improve
battery safety and provide continuous operation in the event of an emergency
at Nine Mile Falls HED.

2.7 Include why the requested amount above is considered a prudent investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project

The health of the critical power system is vital to plant operations and safety. Proper battery storage in a temperature controlled environment greatly reduces
the risk of battery failure. Additionally, moving the batteries outside the
powerhouse reduces the safety risk to plant personnel and potential damage to
batteries due to other plant operations.

During project design, construction, and commissioning, the project will be
continually evaluated to ensure the goals of the project are being met. Remote
room temperature, battery condition and hydrogen monitoring will be utilized to
verify the temperature control of the environment. Access to the building will be limited to essential personnel to limit and minimize any safety risks to personnel and equipment. Battery discharge testing and subsequent recharging will also
2021 -
Continued
Engineering
Q1 2022 -RFP -
contract award
Q2 2022 -
Construction
(90 days to 120
days)
Q3 2022 -TTP -
In-service
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 201 of 309
Nine Mile Battery Building
Business Case Justification Narrative Template Version: 08/04/2020 Page 7 of 9
evaluate the performance of the system prior to project completion and
periodically throughout the life the system.

2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
• GPSS Project Delivery (engineering and project management)
• Spokane River Plant Operations
• Battery Maintenance and Testing
• Spokane River Permitting and Environmental
• Supply Chain (contracts management)
• Power Supply
• Hydro Compliance

2.8.2 Identify any related Business Cases

N/A

3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
Steering committee members consist of the Manager of Hydro Operations &
Maintenance, the Manager of Spokane River Hydro Operations and the
Manager of Controls & Electrical Engineering. The Battery Maintenance &
Testing team will serve as an Advisory Group for this project.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 202 of 309
Nine Mile Battery Building
Business Case Justification Narrative Template Version: 08/04/2020 Page 8 of 9
3.2 Provide and discuss the governance processes and people that will provide oversight
This project will be governed by the methods described in the GPSS PM
Process Flow document. Governance tasks will include monthly project reports,
quarterly project updates, business case updates, the monthly monitoring of
project costs and schedule, tracking changes, monitoring risks and issues,
communications including project meetings and stakeholder communication.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
The creation and utilization of a Risk Registry will provide for the identification
of risks and their analysis. In the event changes are needed, documentation will
be presented to the steering committee who is solely authorized to approve said changes.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 203 of 309
Nine Mile Battery Building
Business Case Justification Narrative Template Version: 08/04/2020 Page 9 of 9

4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Nine Mile Falls HED Battery Room
and agree with the approach it presents. Significant changes to this will be coordinated with
and approved by the undersigned or their designated representatives.

Signature:

Date: 7/7/2021
Print Name: Jeremy Winkle
Title: Controls/Electrical
Engineering Manager

Role: Business Case Owner

Signature:

Date: 7/12/2021
Print Name: Andy Vickers
Title: Director of GPSS
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 204 of 309
Nine Mile Powerhouse Crane Rehab
Business Case Justification Narrative Page 1 of 8
EXECUTIVE SUMMARY

The Nine Mile Falls Generator Bay and Access Bay bridge cranes were replaced in 1993
prior to the Units 3 and 4 replacement project. Both cranes are Kone brand 35ton cranes with service class for both cranes being H1 – light duty. The Nine Mile powerhouse
cranes are now beyond their useful life. Their duty cycle is too low to support continuous
work during future unit overhauls with both replacement controls and mechanical parts
no longer supported by the manufacturer and must be custom fabricated. The Generator
floor crane trolley is now out of service, limiting Avista’s capability to respond to a turbine generator failure. During the 2018 Maintenance Assessment, the cranes were identified
as high risk due to their current condition.

The recommended solution includes replacement of each crane’s hoist and trolley system
and installing a modern hoist and trolley. This approach is a modern in-kind replacement of the current powerhouse cranes and would provide a lasting solution to meet current
and future crane demands.

The estimated cost of the project is $1,500,000 in order to rehabilitate both bridge cranes.
The service code for this program is Electric Direct and the jurisdiction for the project is Allocated North serving our electric customers in Washington and Idaho. Operating Nine
Mile safely and reliably provides our customers with low cost, reliable power while
ensuring the region has the resources it needs for the Bulk Electric System (BES).

VERSION HISTORY
Version Author Description Date Notes Draft Ryan Bean Initial draft of original business case 7/1/2019 1.0 Ryan Bean Updated Approval Status 7/2/2019 Full amount approved 2.0 Ryan Bean BCFCR Submitted 5/6/2020 Accelerate Funding
3.0 Ryan Bean 5 Year Planning 2020 & New Form 7/8/2020

GENERAL INFORMATION
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 205 of 309
Nine Mile Powerhouse Crane Rehab
Business Case Justification Narrative Page 2 of 8

1. BUSINESS PROBLEM

1.1 What is the current or potential problem that is being addressed?
The Nine Mile Falls bridge cranes were replaced in 1993 prior to the Units 3 and
4 replacement project. Both cranes are Kone brand 35ton cranes. Service class
for both cranes is H1 – light duty. The light duty means infrequent use in a
powerhouse or seldom used warehouse setting.
These cranes are now beyond their useful life. Recent maintenance and deeper
investigation have resulted in one crane being removed from service and the
other having a finite amount of life left.

1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer.
The driver for this business case is Failed Plant. The generator floor crane is no longer available, and the access bay crane has a finite amount of life left placing future repair and refurbishment activities at risk. Nine Mile supplies
year-round base load hydroelectric power to Avista’s portfolio. Continuing to
operate Nine Mile safely and reliably provides our customers with low cost,
reliable power while ensuring the region has the resources it needs for the Bulk Electric System (BES).

1.3 Identify why this work is needed now and what risks there are if not approved or is deferred
These cranes are critical to repair and refurbishment work necessary to maintain
and overhaul generating equipment. Many of the electrical control components
of the crane are now obsolete, and retrofitting the with other parts is not possible.
Many mechanical parts are no longer produced such that replacement parts
Requested Spend Amount $1,500,000
Requested Spend Time Period 2 years
Requesting Organization/Department C07/GPSS
Business Case Owner | Sponsor Ryan Bean | Bob Weisbeck
Sponsor Organization/Department C07/GPSS
Phase Initiation
Category Project
Driver Failed Plant & Operations
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 206 of 309
Nine Mile Powerhouse Crane Rehab
Business Case Justification Narrative Page 3 of 8
must be custom fabricated. If the work is not addressed, this will lead to
extended down time due for repairs, increased O&M costs, and impacting
schedules of future repair and overhaul work.

1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the need listed above.
The measure of success would be in restoring the capabilities of the
powerhouse cranes. This could be captured in reduced crane downtime,
reduced O&M for crane repairs, and decreased risk to future project schedules
due to crane failures. With the current generator bay crane trolley out of service,
overhauls of any major turbine generator equipment may not be possible at this time.

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem.
See Nine Mile Falls HED Bridge Crane Replacement Basis of Design
Report
1.5.2 For asset replacement, include graphical or narrative representation of metrics associated with the current condition of the asset that is
proposed for replacement.
The metric supporting the replacement of the current cranes is that one is
no longer functional and other has a finite number of start/stops left. Major
repairs to turbine generator equipment may not be feasible and future projects will be impacted without cranes readily available.

During the 2018 Maintenance Assessment, the cranes were identified as
high risk due to their current condition.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 207 of 309
Nine Mile Powerhouse Crane Rehab
Business Case Justification Narrative Page 4 of 8
Option Capital Cost Start Complete
Alternative 2: Replace Hoists, Trolleys, Bridge crane drives and controls $1,500,000 01 2023 12 2024
Alternative 1: Replace Crane control system $500,000 01 2023 12 2024
Continue to repair current system (O&M) 01 2021
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.

The failure of the system is the primary metric for justification of the project. During the higher usage periods, we have seen issues with various aspects of
the cranes, mostly having to do with the controls and electrical systems. During
the most recent unit replacement project for Units 1 and 2, the general
construction contractor used the crane on an almost constant basis during concrete demolition activities to remove rubbleized concrete from the powerhouse. Numerous instances of thermal overload occurred on the crane
due to the high usage, causing work stopped and project delays.

Many of the electrical control components of the crane are now obsolete and retrofitting the with other parts is not possible. Many mechanical parts are no longer produced such that replacement parts must be custom fabricated.

2.2 Discuss how the requested capital cost amount will be spent in the current year (or future years if a multi-year or ongoing initiative). (i.e. what are the expected functions, processes or deliverables that will result from the capital spend?). Include any known or estimated reductions to O&M as a result of this investment.

The capital cost will be spread out over two years. The first year will be primarily
design, sourcing, and installation of equipment for the first crane. This is estimated to be $750,000. The second year will include design, sourcing, and installation of equipment for the first crane. This is estimated to be $750,000.
This will not offset significant O&M charges because the one crane has failed
so it is no longer maintained, while the other has minimal inspection and
maintenance performed.

2.3 Outline any business functions and processes that may be impacted (and how) by the business case for it to be successfully implemented.

The execution of this project will enable the needed overhaul of Nine Mile Units
3 & 4. The unit controls and many mechanical components are at the end of
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 208 of 309
Nine Mile Powerhouse Crane Rehab
Business Case Justification Narrative Page 5 of 8
their useful life. Plant production and reliability will be impacted without the
availability of cranes.
2.4 Discuss the alternatives that were considered and any tangible risks and mitigation strategies for each alternative.
Do Nothing: This alternative includes doing nothing with the existing cranes.
Maintaining them as is without replacing any electrical or mechanical
components. This would include the continual maintenance and/or replacement
of parts, where possible. This will lead to continued periods of crane down-time for necessary repairs or part replacements. It will also maintain the thermal overload issue that we have been experiencing during high levels of use.
The approximate capital cost to this alternative is $0 initially. However, future
costs could be substantial if crane down time causes delays during maintenance
or Unit overhaul projects. These future costs are anticipated to be all O&M costs related to maintaining the crane as necessary.
Alternative 1: Replace crane control system. This alternative would include
removing the existing control system on the two bridge cranes and replacing
them with a modern Magnatek VFD control system. This alternative would
ensure that the control system is robust and reliable, however would not address the thermal overload issues with extended use, nor the custom mechanical parts needed for each repair.
Alternative 2: Preferred Alternative: Replace Hoists, Trolley’s, Bridge crane
drives and controls. This alternative would include replacing each crane’s hoist
and trolley system and installing a modern hoist and trolley. This alternative also includes replacement of the controls system with the Magnatek system discussed in Alternative 1. This would include Hoist VFD controls, VFD controls
on the hoist trolley and a new bridge panel with VFD controls that will hook to
the current end truck motors. This option is a modern in-kind replacement of
the current powerhouse cranes and would provide a lasting solution to meet current and future crane demands.

2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer. spend, and transfers to plant by year.

This project is expected to take two years. The effort in the first year will be
devoted design, equipment sourcing, and replacement of the first crane. The
effort in the second year will consist of equipment sourcing and replacement of the second crane. The transfer to plant will be at the end of each year with the completion of commissioning of each crane.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 209 of 309
Nine Mile Powerhouse Crane Rehab
Business Case Justification Narrative Page 6 of 8
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.

Operating Nine Mile safely and reliably provides our customers with low cost, reliable power while ensuring the region has the resources it needs for the Bulk
Electric System (BES). By taking care of this plant we support our mission of
improving our customer’s lives through innovative energy solutions which
includes hydroelectric generation. By executing this project, we ensure that Nine Mile will continue to provide reliable service and mitigate risk to future projects and fielding unplanned failures.

2.7 Include why the requested amount above is considered a prudent investment, providing or attaching any supporting documentation. In addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
Industrial cranes of this size and complexity fall into this range of cost. We are
currently operating at risk with our units in not being able to respond to failed turbine generator equipment in a timely manner thereby, incurring substantial lost generation and O&M.
A formal Project Manager will be assigned to a project of this size. The project
will be managed within project management practices adopted by the
Generation Production and Substation Support (GPSS) department. This includes the creation of a Steering Committee and a formal Project Team. Once the project is initiated, reporting on scope, schedule and cost will occur monthly.
Changes in scope, schedule, or cost will be surfaced by the Project Manager to
the Steering Committee for governance. The Project Manager will manage the
project through its conclusion.

2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
The primary stakeholders for this project are, the Hydro Regional Manager
on the Upper Spokane, the Upper Spokane plant personnel, GPSS
Engineering, GPSS Construction and Maintenance, and Power Supply.
Other stakeholders may be identified during project initiation.

2.8.2 Identify any related Business Cases
This project will need to be completed prior to overhaul of Units 3 & 4, or
any repairs to any major equipment on the generator floor.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 210 of 309
Nine Mile Powerhouse Crane Rehab
Business Case Justification Narrative Page 7 of 8
3.1 Steering Committee or Advisory Group Information
A formal Project Manager will be assigned to a project of this size. The project
will be managed within project management practices adopted by the Generation Production and Substation Support (GPSS) department. A Steering Committee will be formed for this project. The Project Manager will manage the
project through its conclusion.
3.2 Provide and discuss the governance processes and people that will
provide oversight
Management of this project will include the creation of a Steering Committee which will include managers representing the key stakeholders involved in this
project. The project will also be executed by a formal Project Team lead by the
Project Manager.
3.3 How will decision-making, prioritization, and change requests be documented and monitored
Once the project is initiated, reporting on scope, schedule and cost will occur
monthly. Changes in scope, schedule, or cost will be surfaced by the Project
Manager to the Steering Committee for governance.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 211 of 309
Nine Mile Powerhouse Crane Rehab
Business Case Justification Narrative Page 8 of 8

The undersigned acknowledge they have reviewed the Cabinet Gorge HVAC
business case and agree with the approach it presents. Significant changes to this
will be coordinated with and approved by the undersigned or their designated
representatives.

Date: 7/30/20
Ryan Bean
Plant Manager, Upper Spokane
Business Case Owner

Date:
Andy Vickers
Director, GPSS
Business Case Sponsor

Date:

Steering/Advisory Committee Review

Template Version: 05/28/2020
7/31/2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 212 of 309
Nine Mile Powerhouse Roof Replacement
Business Case Justification Narrative Template Version: 04.21.2022 Page 1 of 7
EXECUTIVE SUMMARY

The Nine Mile Falls generation plant is over 100 years old. The roof trusses and concrete
slab is original construction, and the roofing membrane was possibly updated in 1984 - 38 years ago or more with temporary patches and repairs since. Many inspections
conducted over the years have determined that the roof is leaking and deteriorating, and
the most recent June 2021 inspection by Garland Roofing stated that “overall the roof
system has come to the end of its serviceable life” and is badly in need of complete
replacement. As the engineering team has investigated the roof’s condition, more
information has come to light revealing that the roof’s steel truss members in their current
state are overstressed supporting the roof system weight (concrete roof slab and roofing
membrane material) alone with no extra capacity for live loads, such as snow. Additional
concerns include the condition of the 100-year-old steel trusses, which have experienced some damage and corrosion over the years and still has the same 100-year-old coating system.

The recommended solution is to address the overstressed condition of the steel trusses
and to replace the failed roof membrane system. The supporting steel truss members will either be upgraded to increase their structural capacity or the concrete roof slab panels be replaced with lighter weight roofing material to reduce load on the steel trusses.

The estimated cost for the roof is $1,000,000 to address both the structural and roofing
needs. The service code for this program is Electric Direct and the jurisdiction for the project is Allocated North serving our electric customers in Washington and Idaho. Operating Nine Mile safely and reliably provides our customers with low cost, reliable
power while ensuring the region has the resources it needs for the Bulk Electric System
(BES).

VERSION HISTORY
Version Author Description Date Notes
Draft Ryan Bean Initial draft of original business case 8/18/2022

GENERAL INFORMATION
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 213 of 309
Nine Mile Powerhouse Roof Replacement
Business Case Justification Narrative Template Version: 04.21.2022 Page 2 of 7

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
The powerhouse roof at Nine Mile needs replacement due to age and deterioration. The
current membrane leaks and the existing roof trusses are in an overstressed condition
that requires remediation.

1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
The driver for this business case is Asset Condition. The powerhouse roof is needed in
good condition to protect the inner workings of the generating plant. Nine Mile supplies
year-round base load hydroelectric power to Avista’s portfolio. Continuing to operate
Nine Mile safely and reliably provides our customers with low cost, reliable power while
ensuring the region has the resources it needs for the Bulk Electric System (BES).

1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
The roof has reached the end of its serviceable life and is structurally deficient. If not
addressed in the near future, the condition of the roof will continue to degrade, exposing
the plant to water infiltration and potential failure due to its overstressed condition.
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the need listed above.
The measure would include restoring the structural integrity and watertight seal of the
roof to provide years of service to come. By restoring the roof, we protect our ability to
generate low-cost power for our customers.

Requested Spend Amount $ 1,000,000
Requested Spend Time Period 1 Year
Requesting Organization/Department C07/GPSS
Business Case Owner | Sponsor Ryan Bean | Alexis Alexander
Sponsor Organization/Department C07/GPSS
Phase Initiation
Category Project
Driver Asset Condition
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 214 of 309
Nine Mile Powerhouse Roof Replacement
Business Case Justification Narrative Template Version: 04.21.2022 Page 3 of 7
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
- NM Roof Structure Analysis Memo
- Roof Truss Steel Coupon Test Results
1.5.2 For asset replacement, include graphical or narrative representation of metrics associated with the current condition of the asset that is proposed for replacement.
Per roofing condition inspection, the roof has reached the end of its useful life.
2. PROPOSAL AND RECOMMENDED SOLUTION

Option Capital Cost Start Complete
1. Address overstress and membrane
condition
$1,000,000 01 2023 12 2023
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
The failure of the existing roofing membrane is the primary metric for justification of the
project. Investigative measures have been taken to determine the exact quality of the
roof and its components. These measures include steel and concrete assessments and
analysis. By addressing the problem, we mitigate the risk of water damaging critical
generating equipment and/or roof failure.

2.2 Discuss how the requested capital cost amount will be spent in the current year (or future years if a multi-year or ongoing initiative). (i.e., what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M because of this investment.
The capital costs will be spread over 1 year. Current investigative efforts will inform
selection of an appropriate structural remedy and those costs will be transferred to this
project. Truss remediation will precede the roof membrane replacement in the fall. This
will not offset significant O&M charges because roofing and roof trusses are low
maintenance items.

2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
The execution of this project will enable the continued operation of Nine Mile Units
HED. Plant production and reliability will be impacted without a sound roof.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 215 of 309
Nine Mile Powerhouse Roof Replacement
Business Case Justification Narrative Template Version: 04.21.2022 Page 4 of 7

2.4 Discuss the alternatives that were considered and any tangible risks and mitigation strategies for each alternative.

OPTION 1: Upgrade the 8 steel trusses by reinforcing the overstressed members to
provide greater capacity.

Pro’s:
• Regardless of what option is chosen, the roof trusses need to be maintained by sand
blasting and painting
• Reinforcing truss members improves strength/capacity of truss for dead load and live
load
Con’s:
• Unloading the truss is tricky and could put a member designed for tension into
compression; applied forces/stresses need monitored
• Lead abatement required (steel truss clean up and painting)

OPTION 2: Reduce the dead load weight on steel trusses by cutting out concrete sections
of the roof and replacing with metal lightweight deck material.
Pro’s:
• Regardless of what option is chosen, the roof trusses need to be maintained by sand
blasting and painting
• Cutting out concrete sections reduces dead weight on truss members
Con’s:
• Uneven areas where cutouts made?? Or can these areas be built up and then a new
membrane applied and not have compromising uneven roof areas that create issues
in the future?
• Dusty & concrete fines need contained (in powerhouse) during concrete cutting
• Lead abatement required (steel truss clean up and painting)

OPTION 3: Perform complete tear off the concrete roof and concrete beams over the
trusses (unless it makes more sense to keep the concrete beams and just remove the slab)
and replace with a new roof (metal deck & membrane roofing).
Pro’s:
• Regardless of what option is chosen, the roof trusses need to be maintained by sand
blasting and painting
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 216 of 309
Nine Mile Powerhouse Roof Replacement
Business Case Justification Narrative Template Version: 04.21.2022 Page 5 of 7
• Reduces dead weight on truss members; new roof material would be much lighter
than existing concrete roof
Con’s:
• Extensive work and could be disruptive to plant operations
• Lead abatement required (steel truss clean up and painting)

2.5 Include a timeline of when this work will be started and completed. Describe when the investments become used and useful to the customer.
Costs will be transferred to plant as the stages of work are completed. First will be the
truss remediation followed by the new roofing membrane.

2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Operating Nine Mile safely and reliably provides our customers with low cost, reliable
power while ensuring the region has the resources it needs for the Bulk Electric System
(BES). By taking care of this plant, we support our mission of improving our customer’s
lives through innovative energy solutions which includes hydroelectric generation. By
executing this project, we ensure that Nine Mile will continue to provide reliable
service and mitigate risk to future projects and fielding unplanned failures.

2.7 Include why the requested amount above is considered a prudent investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
Nine Mile HED is Avista’s fifth largest hydroelectric plant. Roof projects of his size and
complexity fall into this range of costs.
A formal Project Manager will be assigned to a project of this size. The project will be
managed within project management practices adopted by the Generation Production
and Substation Support (GPSS) department. This includes the creation of a Steering
Committee and a formal Project Team. Once the project is initiated, reporting on
scope, schedule and cost will occur monthly. Changes in scope, schedule, or cost will
be surfaced by the Project Manager to the Steering Committee for governance. The
Project Manager will manage the project through its conclusion.

2.8 Supplemental Information

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 217 of 309
Nine Mile Powerhouse Roof Replacement
Business Case Justification Narrative Template Version: 04.21.2022 Page 6 of 7
2.8.1 Identify customers and stakeholders that interface with the business case
The primary stakeholders for this project are, the Hydro Regional Manager on the
Upper Spokane, the Upper Spokane plant personnel, GPSS Engineering, GPSS
Construction and Maintenance, and Power Supply. Other stakeholders may be
identified during project initiation.

2.8.2 Identify any related Business Cases
This project will need to be sequenced with several other projects that are in process
including crane overhauls and Unit 3 & 4 overhauls.

3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
A formal Project Manager will be assigned to a project of this size. The project will be
managed using project management practices adopted by the Generation Production
and Substation Support (GPSS) department. A Steering Committee will be formed for
this project. The Project Manager will manage the project through its conclusion.

3.2 Provide and discuss the governance processes and people that will
provide oversight
Management of this project will include the creation of a Steering Committee which
will include managers representing the key stakeholders involved in this project. The
project will also be executed by a formal Project Team lead by the Project Manager.
3.3 How will decision-making, prioritization, and change requests be documented and monitored?
Once the project is initiated, reporting on scope, schedule and cost will occur monthly.
Changes in scope, schedule, or cost will be surfaced by the Project Manager to the
Steering Committee for governance.

4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Nine Mile Powerhouse Roof Replacement
project and agree with the approach it presents. Significant changes to this will be coordinated with
and approved by the undersigned or their designated representatives.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 218 of 309
Nine Mile Powerhouse Roof Replacement
Business Case Justification Narrative Template Version: 04.21.2022 Page 7 of 7
Signature: Date:
Print Name: Ryan Bean
Title: Plant Manager
Role: Business Case Owner

Signature: Date:
Print Name: Alexis Alexander
Title: Director, GPSS
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 219 of 309
Nine Mile Unit 3 Mechanical Overhaul
Business Case Justification Narrative Page 1 of 8
EXECUTIVE SUMMARY

The original Unit 3 was replaced with a new American Hydro unit in 1995. Unit 3
experienced cracked buckets on the runners in 2010. This was found to be due to heavy
wear due to erosion from sediment and cavitation damage. The cracks were repaired; however the sediment wear has continued and bucket failure is anticipated. The installed
roller guide bearing also does not provide the thrust bearing support it was designed to,
causing the upstream generator guide bearing to take the entire thrust loading of the
machine. This condition puts increased stress and wear on the generator bearings and
increases the risk of failure. During the 2018 Maintenance Assessment, this bearing was identified as high risk due to its current condition. If left unaddressed, the Unit is likely to
experience bucket or bearing failure resulting in extended down time and lost generation.

The recommended solution is to mechanical overhaul the Unit including installing new
Francis Runners, new downstream water lubricated bearing and pedestal, new combination thrust/guide bearing with thrust shaft, and refurbishment of the wicket gate
stems and all operating components. This alternative would provide a lasting solution to
the problems outlined above and avoid a costly unanticipated failure.

The estimated cost of the project is $6,500,000. The service code for this program is Electric Direct and the jurisdiction for the project is Allocated North serving our electric
customers in Washington and Idaho. Operating Nine Mile safely and reliably provides
our customers with low cost, reliable power while ensuring the region has the resources
it needs for the Bulk Electric System (BES).

VERSION HISTORY
Version Author Description Date Notes
Draft Ryan Bean Initial draft of original business case 6/21/2019
1.0 Ryan Bean Updated Approval Status 7/2/2019 Full amount approved
2.0 Ryan Bean 5 Year Planning 2020 & New Form 7/8/2020
3.0 Ryan Bean 5 Year Planning 2021 7/2/2021
4.0 Ryan Bean Annual Update 7/29/2022 No Changes

GENERAL INFORMATION
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 220 of 309
Nine Mile Unit 3 Mechanical Overhaul
Business Case Justification Narrative Page 2 of 8

1. BUSINESS PROBLEM

1.1 What is the current or potential problem that is being addressed?
The original Unit 3 at Nine Mile was replaced with new American Hydro unit in
1995. Unit 3 experienced cracked buckets on the runners in 2010. This was
found to be due to heavy wear due to erosion from sediment and cavitation
damage. The cracks were repaired; however, the sediment wear has continued and bucket failure is anticipated. The runners, as well as other critical
mechanical components are not performing and are approaching end of life.

1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer.
The driver for this business case is Asset Condition. Several critical
components of the unit are at or approaching end of life. Nine Mile supplies year-round base load hydroelectric power to Avista’s portfolio. Continuing to operate Nine Mile safely and reliably provides our customers with low cost,
reliable power while ensuring the region has the resources it needs for the Bulk
Electric System (BES).

1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
If the condition of this Unit is left unaddressed, the Unit is likely to experience
bucket or bearing failure resulting in extended down time and lost generation. In the event of an unanticipated failure, procuring new replacement runners would likely take at least 8-12 months to procure, resulting in substantial loss of
power generation.
Requested Spend Amount $6,500,000
Requested Spend Time Period 4 years
Requesting Organization/Department C07/GPSS
Business Case Owner | Sponsor Ryan Bean | Andy Vickers
Sponsor Organization/Department C07/GPSS
Phase Initiation
Category Project
Driver Asset Condition
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 221 of 309
Nine Mile Unit 3 Mechanical Overhaul
Business Case Justification Narrative Page 3 of 8
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
The investment would be fielded in several phases over the course of two years. The design, procurement, and installation specifications of the new equipment
would be overseen by GPSS Engineering as part of a project team. The
measure of success would consist of a successful commissioning of the unit,
with performance meeting the specifications, and providing reliable power generation with reduced O&M for years to come.

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem.
Supporting Reference Docs: See 2010 Unit 3 Bucket Repair
documentation and Unit 4 Mechanical Overhaul Project documentation.
1.5.2 For asset replacement, include graphical or narrative representation of metrics associated with the current condition of the asset that is proposed for replacement.
The metric supporting the overhaul of the current system is that it is at or
approaching end of life. In addition to worn runners, the installed F.A.G.
roller guide bearing also does not provide the thrust bearing support it was
designed to, causing the upstream generator guide bearing to take the entire thrust loading of the machine. The bearing supports the full thrust
loading on a small thrust collar that was not designed for it, resulting in
additional wear and heating. This condition puts increased stress and
wear on the generator bearings and increases the risk of failure.

During the 2018 Maintenance Assessment, this bearing was identified as
high risk due to its current condition.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 222 of 309
Nine Mile Unit 3 Mechanical Overhaul
Business Case Justification Narrative Page 4 of 8

Option Capital Cost Start Complete
Alternative 1: Overhaul the Unit $6,500,000 01 2022 12 2025
Continue to repair current system (O&M) $0 01 2022

2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.

A similarly scoped project was performed on Nine Mile Unit 4 several years ago.
Project cost estimates and construction experience from the project were used to estimate a nearly identical body of work for Unit 3.

2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include any known or estimated reductions to O&M as a result of this investment.

The capital cost will be spread out over four years. The first year will be primarily
engineering design and sourcing of the equipment. The second and third year
will include the bulk of procurement and construction including equipment removal, new equipment installation. The fourth year will be as-builds,
commissioning, and project clean up. This will offset annual O&M maintenance
charges in responding to failed components and mitigate the risk of
unanticipated failures.

2.3 Outline any business functions and processes that may be impacted (and how) by the business case for it to be successfully implemented.

The execution of this project will enable reliable power production services to
Power Supply by executing a planned upgrade vs an unanticipated failure.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 223 of 309
Nine Mile Unit 3 Mechanical Overhaul
Business Case Justification Narrative Page 5 of 8
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Do Nothing: While the Unit is capable of continued operation in its current state, the likelihood of catastrophic failure due to runner or bearing failure is increasing. Due to the engineering required and long lead times on this
equipment, the financial impacts of a failure would be substantial due to
extended down time. Given the current bearing condition and known wear on
the runners, doing nothing is not a preferred option.
Alternative 1: Mechanical overhaul of the unit including new Francis Runners, new downstream water lubricated bearing and pedestal, new combination
thrust/guide bearing with thrust shaft, and refurbishment of the wicket gate
stems and all operating components (operating ring, operating shafts, wear
pads, etc.). This alternative would provide a lasting solution to the problems outlined above and avoid a costly unanticipated failure.

2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
spend, and transfers to plant by year.

This project is expected to take four years. The first year will be primarily
engineering design and sourcing of the equipment. The second and third year
will include the bulk of procurement and construction including equipment
removal, new equipment installation. The fourth year will be as-builds, commissioning, and project clean up. The transfer to plant will be at the end of the third year with the completion of commissioning.

2.6 Discuss how the proposed investment aligns with strategic vision, goals, objectives and mission statement of the organization.

Operating Nine Mile safely and reliably provides our customers with low cost,
reliable power while ensuring the region has the resources it needs for the Bulk
Electric System (BES). By taking care of this plant we support our mission of
improving our customer’s lives through innovative energy solutions which includes hydroelectric generation. By executing this project, we ensure that
Nine Mile will continue to provide reliable service and mitigate risk to future
projects and fielding unplanned failures.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 224 of 309
Nine Mile Unit 3 Mechanical Overhaul
Business Case Justification Narrative Page 6 of 8
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed and re-evaluated throughout the project
Industrial equipment of this size and complexity fall into this range of cost. A
formal Project Manager will be assigned to a project of this size. The project
will be managed within project management practices adopted by the
Generation Production and Substation Support (GPSS) department. This includes the creation of a Steering Committee and a formal Project Team. Once the project is initiated, reporting on scope, schedule and cost will occur monthly.
Changes in scope, schedule, or cost will be surfaced by the Project Manager to
the Steering Committee for governance. The Project Manager will manage the
project through its conclusion.

2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
The primary stakeholders for this project are, the Hydro Regional Manager
on the Upper Spokane, the Upper Spokane plant personnel, GPSS
Engineering, GPSS Construction and Maintenance, Environmental, and Power Supply. Other stakeholders may be identified during project initiation.

2.8.2 Identify any related Business Cases
A predecessor to this project included overhaul of the plant cranes. There is separate business case supporting this work, which must be completed
prior to performing a mechanical overhaul.

This project should be completed in conjunction with replacement of the
aged Baily control system. There is a separate project business case built to support that work, which should be completed during the same overhaul
window.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 225 of 309
Nine Mile Unit 3 Mechanical Overhaul
Business Case Justification Narrative Page 7 of 8
3.1 Steering Committee or Advisory Group Information
A formal Project Manager will be assigned to a project of this size. The project
will be managed within project management practices adopted by the Generation Production and Substation Support (GPSS) department. A Steering Committee will be formed for this project. The Project Manager will manage the
project through its conclusion.
3.2 Provide and discuss the governance processes and people that will
provide oversight
Management of this project will include the creation of a Steering Committee which will include managers representing the key stakeholders involved in this
project. The project will also be executed by a formal Project Team lead by the
Project Manager.
3.3 How will decision-making, prioritization, and change requests be documented and monitored
Once the project is initiated, reporting on scope, schedule and cost will occur
monthly. Changes in scope, schedule, or cost will be surfaced by the Project
Manager to the Steering Committee for governance.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 226 of 309
Nine Mile Unit 3 Mechanical Overhaul
Business Case Justification Narrative Page 8 of 8
The undersigned acknowledge they have reviewed the Nine Mile Unit 3 Mechanical Overhaul business case and agree with the approach it presents.
Significant changes to this will be coordinated with and approved by the
undersigned or their designated representatives.
Business Case Owner
Business Case Sponsor
Steering/Advisory Committee Review
Template Version: 05/28/2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 227 of 309
Nine Mile 3 & 4 Controls Upgrade
Business Case Justification Narrative Template Version: 04.21.2022 Page 1 of 6
EXECUTIVE SUMMARY

Nine Mile Units 3 and 4 controls were installed in the early 1990’s and are at the end of their intended life and there is an increased likelihood of forced outages and subsequent loss of
revenue and reliability. A controls upgrade including speed controllers (governors), voltage controls (automatic voltage regulator or AVR), primary unit control system (i.e., Unit PLC), and the upgraded protective relay system is needed on units 3 and 4. During the 2018 Maintenance
Assessment, the Unit controls were rated in poor condition and high in risk due their age and current condition. Included in the scope of this project is replacement of the switchgear floor inside the Nine Mile powerhouse that will be utilized for relocation of the unit controls and
voltage regulation equipment. In 2010, this floor was found to be inadequate for any loading above and beyond what it is currently supported, and partially replaced during the Unit 1 and
2 replacement project. The reminder of the floor will need to be replaced to ensure adequate
floor loading can be achieved.

The completion of this project will reduce maintenance costs and improve reliability delivered
to Avista’s customers as upgrading the controls, monitoring, and protection will reduce unplanned outages. The cost of the solution is estimated to be about $4,125,000 per unit at
this time. This solution will address issues of obsolescence, increased likelihood of unplanned
outages, and performance needs to work with the new dynamics of modern systems. This includes integration of intermittent resources, reserves, frequency and voltage response, and
the ability to adapt these controls and protection devices as the larger grid continues to evolve.
If this business case is not approved the risks above would continue as the asset condition continues to decline. The recommended solution was reviewed by GPSS Engineering and
approved by GPSS Management.

ERSION HISTORY
Version Author Description Date Notes
1.0 Kristina Newhouse
Ryan Bean Initial submission 7/2/2019
2.0 Kristina Newhouse Updated to 2020 template 7/31/2020
3.0 Kristina Newhouse
& PJ Henscheid
Updated to 2022 template and modified
budget to align with improved estimates
8/23/2022

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 228 of 309
Nine Mile 3 & 4 Controls Upgrade
Business Case Justification Narrative Template Version: 04.21.2022 Page 2 of 6
GENERAL INFORMATION
1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
The problem is that Nine Mile Units 3 and 4 controls are obsolete, unsupported and in overall poor condition. Upgrading the speed controllers (governors), voltage controls (automatic voltage regulator a.k.a. AVR), primary unit control system (i.e., PLC), and
the protective relay system will address issues of obsolescence, increased likelihood of unplanned outages, and performance needs to work with the new dynamics of modern systems. Also, the switchgear floor is inadequate to support additional loading
for new equipment to be place. Replacing the remainder of the floor will ensure adequate floor loading can be achieved.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
The major driver of this business case is Asset Condition. There have been unit outages that were specifically taken to address problems associated with the existing control
and protection equipment. Problems with the governor and wicket gate actuating
mechanisms continue to affect unit reliability. The current governor system is undersized to handle the required load, causing startup and speed control issues.
Customers benefit in that it will allow Avista to economically optimize an existing asset
to provide energy and other energy related products.
1.3 Identify why this work is needed now and what risks there are if not approved or
is deferred
During the 2018 Maintenance Assessment, the Unit controls were rated in poor condition and high in risk due their age and current condition. This equipment is at the
end of its intended life and there is an increased likelihood of forced outages and
subsequent loss of revenue and reliability.
1.4 Identify any measures that can be used to determine whether the investment
would successfully deliver on the objectives and address the need listed above.
A successful investment to upgrade the Nine Mile 3 & 4 Control Monitoring, and Protection systems would be measurable by Future Maintenance Assessments that
would show an improved condition and reduction in risk.
Requested Spend Amount $8,250,000
Requested Spend Time Period 4 year
Requesting Organization/Department GPSS
Business Case Owner | Sponsor Kristina Newhouse | Alexis Alexander
Sponsor Organization/Department GPSS
Phase Planning
Category Project
Driver Asset Condition
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 229 of 309
Nine Mile 3 & 4 Controls Upgrade
Business Case Justification Narrative Template Version: 04.21.2022 Page 3 of 6
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
The following files from the 2018 Maintenance Assessment can be found at (c01m114) G:\Generation\Asset Management\GPSS Condition Assessment Forms and References\Condition Assessment - NM
• Nine Mile Hydro AMP 041912.xlsx file
• NM Lifecycle Cost Calculator 061918.xlsx

1.5.2 For asset replacement, include graphical or narrative representation of metrics associated with the current condition of the asset that is proposed for
replacement.
The following graphs illustrate the Lifecyle Cost Analysis that was done as part of
the 2018 Maintenance Assessment.

2. PROPOSAL AND RECOMMENDED SOLUTION
The recommended solution is to replace unit control, monitoring, and protection systems. In
addition to addressing issues of obsolescence and increased likelihood of unplanned outages, replacement of these key systems addresses the performance needs to work with
the new dynamics of the systems today. This includes integration of intermittent resources,
reserves, frequency and voltage response, and the ability to adapt these controls and protection devices as the larger grid continues to evolve. It also includes replacement of the switchgear floor to adequately support the new equipment to be placed.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 230 of 309
Nine Mile 3 & 4 Controls Upgrade
Business Case Justification Narrative Template Version: 04.21.2022 Page 4 of 6
Option Capital Cost Start Complete
[Recommended Solution] Replace Unit Control,
Monitoring, and Protection Systems
$8.250M 01 20222 12 2026
[Alternative #1] $M MM YYYY MM YYYY
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
The 2018 Maintenance Assessment was considered in preparing this capital request (see section 1.5.)
2.2 Discuss how the requested capital cost amount will be spent in the current year (or future years if a multi-year or ongoing initiative). (i.e., what are the expected functions,
processes or deliverables that will result from the capital spend?). Include any known or
estimated reductions to O&M as a result of this investment.
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]
The requested capital costs will cover design, material, factory acceptance testing,
installation, and commissioning. To accomplish project objectives to improve unit response, operating flexibility, and reliability, the following components will be
considered: governor and governor controls, generator excitation system and AVR,
protective relays, and unit controls. The objective is to ensure system compatibility with current standards and improve system reliability.
2.3 Outline any business functions and processes that may be impacted (and how) by the business case for it to be successfully implemented.
Resources will need to be allocated by each stakeholder listed in 2.8.1 for the project
to be carried out from initiation to completion.
This project will benefit Power Supply and System Operations as they are responsible for dispatching power from Cabinet Gorge plant to meet contractual obligations and
managing the day-to-day transmission system operational requirements. It will also benefit engineering and the shops as they are responsible for providing maintenance
and support with the generating facilities.
2.4 Discuss the alternatives that were considered and any tangible risks and mitigation strategies for each alternative.
While the generator is capable of producing energy with existing systems, this solution
requires maintenance of old systems that are no longer supported by the original manufacturer and there is some question on parts availability. Additionally, trained
personnel available to work on these older systems are becoming scarce and formal
training is no longer available. For reasons of obsolescence, inadequate system performance, and increasing maintenance demands, this option is not the preferred
option.
No other options were considered due to the extensive age of the various systems and the difficulty to upgrade only a portion of the technology as new technology is
incompatible with the obsolete technology.
2.5 Include a timeline of when this work will be started and completed. Describe
when the investments become used and useful to the customer.
The business case will include 2 projects, one for Unit 3 and another for Unit 4. Design and Construction for each project take place over 3 years with the
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 231 of 309
Nine Mile 3 & 4 Controls Upgrade
Business Case Justification Narrative Template Version: 04.21.2022 Page 5 of 6
design of unit 4 starting during construction of unit 3. Each project with be transferred to plant at the completion of construction.

2022 2023 2024 2025
$500,000 $3,250,000 $3,000,000 $1,500,000

2.6 Discuss how the proposed investment aligns with strategic vision, goals, objectives and mission statement of the organization.
Replacing obsolete and problematic control equipment on unit 3 and unit 4 will increase
reliability and efficiencies at Nine Mile HED. This program safely, responsibly, and
affordably improves our customers’ lives through innovative energy solutions.
2.7 Include why the requested amount above is considered a prudent investment, providing or attaching any supporting documentation. In addition, please explain how the investment prudency will be reviewed and re-evaluated throughout the
project
We cannot continue to operate units 3 and 4 at Nine Mile HED and expect the same results as when the controls were installed over 20 years ago. Technology has
improved and the expectations for automation and monitoring continue to increase. The installation of new controls and protection will also provide increased visibility into the
systems allowing better remote monitoring and troubleshooting. If we do not invest and
take care of these two units, they will continue to be unreliable and fall further behind in technology that other upgraded units operate with.
2.8 Supplemental Information 2.8.1 Identify customers and stakeholders that interface with the business case
The following stakeholders will interface with this business case:
• Controls Engineering
• Electrical Engineering
• Mechanical Engineering
• Protection Engineering
• SCADA Engineering
• Project Management
• PCM Shop
• Electric Shop
• Mechanic Shop
• Hydro Operations

2.8.2 Identify any related Business Cases
This Business Case is being coordinated with the Nine Mile Unit 3 Mechanical Overhaul

3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
The steering committee will minimally consist of the Controls Engineering Manager,
the Electrical Engineering Manager, The Mechanical Engineering Manager, The
Unit 3 Design Unit 3
Design
Unit 4 Design Unit 4 Construction
Unit 3
Construction
Unit 4 Design
Unit 3 Construction
Unit 4 Construction Unit 4 As-built
Unit 3 As-built
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 232 of 309
Nine Mile 3 & 4 Controls Upgrade
Business Case Justification Narrative Template Version: 04.21.2022 Page 6 of 6
protection Engineering Manager, the Protection Control Meter Technician Foreman, and the Spokane River Plant and Operations Manager.
3.2 Provide and discuss the governance processes and people that will provide
oversight
More detailed project governance protocols will be established during the project
chartering process. The Steering Committee will allocate appropriate resources to all
project activities, once the scope is better defined.
3.3 How will decision-making, prioritization, and change requests be documented
and monitored
Project decisions will be coordinated by the project manager. The Steering Committee will be advised when necessary. Regular updates will be provided to the
Steering Committee by the project manager as project scope, schedule and budget are defined, and through the course of the project execution.
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Nine Mile Unit 3 & 4 Control
Upgrade business case and agree with the approach it presents. Significant changes to this will be coordinated with and approved by the undersigned or their designated representatives.

Signature: Date: 8/24/2022
Print Name: Kristina Newhouse
Title: Controls/Electrical Eng Mgr
Role: Business Case Owner

Signature: Date:
Print Name:
Title:
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 233 of 309
Noxon Rapids Generator Step-Up Bank C Replacement
Business Case Justification Narrative Template Version: 04.21.2022 Page 1 of 6
EXECUTIVE SUMMARY

Unit 5 at Noxon Rapids HED has its own generator step-up transformers referred to as Bank C. This is original equipment and has been well maintained. Periodic oil samples of each
transformer are taken periodically. The test results are compared to IEEE standards to help
determine the health of the asset. As these numbers change, it helps explain what is going on inside the transformer and how things are wearing out. There are no spares for these
transformers so if anyone of them fail then the generating unit will be out of service. It is
recommended that the Bank C be replaced. The total cost of this project is estimated to be $4,011,000. The cost of similar completed projects were also taken into consideration.

Replacing Bank C at Noxon Rapids HED is a benefit to the customers as it will improve the
reliability of the generating unit and keep one of Avista’s largest sources of power available to the
customers. If this project is not approved, then upon a transformer failure there would be a loss of 100 MW for the duration of an unplanned outage. In the case of a failure, resources would be required to move from other projects to address this issue. After assessing the damage, a path
forward would be determined. The recommended solution was reviewed by GPSS Engineering and approved by GPSS Management.

VERSION HISTORY
Version Author Description Date Notes
1.0 Glen Farmer Original submission 7/10/2017
2.0 Glen Farmer Updated to 2020 template and timeline
to reflect current 5-year plan 8/1/2020
3.0 Kristina Newhouse Updated to 2022 template and timeline
to reflect current 5-year plan 8/19/2022

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 234 of 309
Noxon Rapids Generator Step-Up Bank C Replacement
Business Case Justification Narrative Template Version: 04.21.2022 Page 2 of 6
GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
The potential problem being address is the asset condition of Unit 5 Step-up transformers. They are original equipment and were manufactured in 1976. The
standard useful life for a Step-Up transformer is 40 years. There is currently no spare transformer to put in if one should fail.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
This equipment is made to order by manufactures specifically for each application. As a result, the lead time to develop specifications, go out for bid, and choose a manufacture is about 3 months. At one point it was expected that once the
manufacturer has a purchase order contract in place, it would typically be about 6 months for manufacturing and a few weeks for delivery. However, this is no longer the
case as lead times for transformers of this size have increased substation ally and
around 2-2.5 years from the date of purchase. If there were to be a failure on bank c the Unit 5 down time would be around 3 years from start to finish including the bid
process. The impact of lost generation for this duration could exceed $16MM. Unit 5 is
valuable due to its size and capability. It is the largest Hydro Unit Avista has in its portfolio. It is used to meet Load Demand and Spinning Reserves needs.
Normally transformer oil is sampled, and a Gas Analysis is done every year. When
elevated levels of gassing that indicate insulation break down, partial discharge, or other signs that the transformer may be experiencing issues are observed, then the
sample rate is increased. Three years ago, the sampling was elevated to every six
months. Test results show elevated gas levels still within acceptable concentrations when compared to IEEE standards and monitoring will continue to take place as the
service life extends beyond its recommended lifecycle.
1.3 Identify why this work is needed now and what risks there are if not approved or is deferred
The transformer was installed 46 years ago. Using the predictive model allows for planning, budgeting and scheduling the work so there is less disruption to the overall
Requested Spend Amount $4,011,000
Requested Spend Time Period 3 years
Requesting Organization/Department GPSS
Business Case Owner | Sponsor Kristina Newhouse | Alexis Alexander
Sponsor Organization/Department GPSS
Phase Initiation
Category Project
Driver Asset Condition
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 235 of 309
Noxon Rapids Generator Step-Up Bank C Replacement
Business Case Justification Narrative Template Version: 04.21.2022 Page 3 of 6
project flow. If this is not approved, then when there is a failure the resources and budget will be moved from other projects to address the failure. The difference in cost for a 3-
month outage and a 27 month on Unit 5 is approximately $15M.
1.4 Identify any measures that can be used to determine whether the investment would successfully deliver on the objectives and address the need listed above.
We will continue to do the maintenance of the transformers and monitoring to determine
the health. This will be categorized in a condition assessment and allow us to compare to other similar types of transformers.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
We have oil sample data that tells use the individual gases being created in the
transformer. We use IEEE standards to predict what the condition of the transformer is. Based on that data and the trend of the gassing we can make a
guess as to how long the transformer will still be operational.
1.5.2 For asset replacement, include graphical or narrative representation of metrics associated with the current condition of the asset that is proposed for
replacement.
2. PROPOSAL AND RECOMMENDED SOLUTION
The recommended solution is to purchase 3 new transformers to replace Bank C as well as
a spare transformer. This is the most feasible as building a spare for the existing equipment would be difficult without the original manufacturer.
Option Capital Cost Start Complete
[Recommended Solution] Purchase 3 transformers
to replace Bank C as well as a spare transformer
$4,011,000 05 2023 06 2025
[Alternative #1] Purchase one transformer and store
as a spare.
$1,673,000 01 2023 12 2024
2.1 Describe what metrics, data, analysis or information was considered when preparing this capital request.
The capital request was developed from budgetary quotes from manufacture and
compared to previous projects of similar type.
2.2 Discuss how the requested capital cost amount will be spent in the current year
(or future years if a multi-year or ongoing initiative). (i.e. what are the expected functions,
processes or deliverables that will result from the capital spend?). Include any known or estimated reductions to O&M as a result of this investment.
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy
Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]
When we purchase the bank of transformers, we will purchase four transformers that with one being a spare. Additional monitoring of the transformers will be available to
the operations group, so they have a better insight to how the transformer is being operated. With a new bank of transformers maintenance will be reduced at the
beginning of the maintenance cycles due to oil sampling.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 236 of 309
Noxon Rapids Generator Step-Up Bank C Replacement
Business Case Justification Narrative Template Version: 04.21.2022 Page 4 of 6
2.3 Outline any business functions and processes that may be impacted (and how) by the business case for it to be successfully implemented.
We would be using predictive failure model rather that a reactive failure model.
2.4 Discuss the alternatives that were considered and any tangible risks and mitigation strategies for each alternative.
The transformers are a unique piece of equipment and to build one that matches could
only be done by the original manufacture. Allis-Chalmers is the original manufacture and they have all the specifications for the original transformers. They are no longer in
business.
For a new bank of transformers, the copper bus, the core steel, the insulation would all be purchased at the same time and would help in matching transformers. The forms
and methods of assembly would also help with matching transformers. The biggest
concern is the impedance of the transformers. If they are not within IEEE standards there would be circulating currents that would cause additional heating.
2.5 Include a timeline of when this work will be started and completed. Describe when the investments become used and useful to the customer.
The first year would be design and procurement. Procurement would likely be
extended if current lead time remain. This project was laid out in hopes that the second would be installation and the project would be used and useful at this point.
The third year would be as-builts and close-out.

2.6 Discuss how the proposed investment aligns with strategic vision, goals, objectives and mission statement of the organization.
The new bank of transformers contributes to the Safe and responsible design,
construction, operation and maintenance of Avista’s generation fleet.
2.7 Include why the requested amount above is considered a prudent investment,
providing or attaching any supporting documentation. In addition, please explain how the investment prudency will be reviewed and re-evaluated throughout the project
This is a prudent investment as there would be a drastic reduction in outage time and lost generation by planning and limiting downtime as much as possible. This project
was ranked based on a ranking matrix to ensure prudent consideration of costs,
scheduling and personnel resources.

2023
•$1,005,000
•Bid
•Design
•Procure
2024
•$2,406,000
•Install
2025
•$600,000
•As-built drawings
•Closeout
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 237 of 309
Noxon Rapids Generator Step-Up Bank C Replacement
Business Case Justification Narrative Template Version: 04.21.2022 Page 5 of 6
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
• Electric shop
• Relay shop
• Engineering
• Operations Protection
• Environmental
• Project Management
• Power Supply
2.8.2 Identify any related Business Cases
None
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
The Steering Committee consists of the following members: Manager of Project
Delivery, Manager of Maintenance and Construction, Manager of Hydro Operations &
Maintenance.
3.2 Provide and discuss the governance processes and people that will provide
oversight
Persons providing oversight include: Generation Electrical Engineering Manager, Manager C&M - Electric Shop and Noxon Rapids Plant Manager.
3.3 How will decision-making, prioritization, and change requests be documented and monitored
Project decisions will be coordinated by the project manager. The Steering Committee
will be advised when necessary. Regular updates will be provided to the Steering Committee by the project manager as project scope, schedule and budget are defined,
and through the course of the project execution

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 238 of 309
Noxon Rapids Generator Step-Up Bank C Replacement
Business Case Justification Narrative Template Version: 04.21.2022 Page 6 of 6
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Noxon Rapids Generator Step-Up
Bank C Replacement business case and agree with the approach it presents. Significant changes to this will be coordinated with and approved by the undersigned or their
designated representatives.

Signature: Date: 8/19/2022
Print Name: Kristina Newhouse
Title: Controls & Electrical Eng Manager
Role: Business Case Owner

Signature: Date:
Print Name:
Title:
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 239 of 309
Noxon Rapids Spillgate Refurbishment
Business Case Justification Narrative Template Version: 04.21.2022 Page 1 of 8
EXECUTIVE SUMMARY
The eight Spillgates at Noxon Rapids HED are over 60 years old and are the
original gates. The Spillgates are critical equipment which control the flow of water
over the dam during spill conditions when the water flowing in the river exceeds
that which passes through the turbines in the plant. They are also protection for
the dam during high flow periods or in the event that the plant or units trip to
prevent overtopping or flooding of the dam. The gates require repair or
replacement due to age, future EIM usage requriements, and structural analysis
which reveals that the current gates may not be designed to meet the loading
requirements during operation and due to seismic conditions. The spillgate issues
must be resolved in the near future for the safety and reliability of the plant
personnel and equipment. Fully functioning spillgates is a FERC requirement and
part of the Dam Safety program. At the time of writing this document, the FERC
was reviewing a site specific seismic hazard assement performed at Noxon
Rapids, the results of which will inform the project on the necessary path forward,
whether the gates are refurbished or if they are required to be replaced.
The path forward and recommended alternative has taken different forms over the
life of this project. It started out as potential refurbishment or replacement of the
gates, however, has morphed into a refurbishment project to strengthen specific
identified weaker members of the gate to meet necessary FERC and design
standards to meet all operating conditions – besides seismic. The FERC is
continuing to review the seismic hazard assessment at Noxon Rapids, which will
inform the necessary seismicity requirements at the facility. However, a potential
outcome of that assessment would be more significant enhancements necessary
across the entirety of the plant, and as such, the determination to proceed with the
strengthening project at this time was prudent to ensure that the spillgates meet all
normal operating requirements. The project budget originally was estimated at
$24.9M, where the revised request is down to $3.85M with the revised scope of
work. The recommended solution was reviewed by GPSS Engineering and
approved by GPSS Management and the project steering committee.

VERSION HISTORY
Version Author Description Date Notes
1.0 PJ Henscheid Format existing BC into exec summary 7.6.20 5-year Capital Planning
2.0 Completion of full BCJN document 8.3.20
3.0 PJ Henscheid Updated to 2022 template and modified 8.24.22

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 240 of 309
Noxon Rapids Spillgate Refurbishment
Business Case Justification Narrative Template Version: 04.21.2022 Page 2 of 8
GENERAL INFORMATION

1. BUSINESS PROBLEM
[This section must provide the overall business case information conveying the benefit to the customer, what
the project will do and current problem statement]
1.1 What is the current or potential problem that is being addressed?
(1) The Noxon Spillgates are nearing the end of their useful life as Avista transitions into the
EIM market. EIM will require the spillgates to be used at greater frequencies than they are today
and with finer movements. The gate mechanisms can’t support these types of and quanity of
movements due to age, material, and design. (2) The gates are structurally insufficient when
compared against the FERC requrements for structural stability when an earthquake hits. If an
earthquake hits and damages the dam such that they are unoperable, that could potentially be
a danger to plant personnel, the community downstream, and Avista’s ability to generalte
electricity in a prudent manner.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
(1) MANDATORY & COMPLIANCE Working and safe tainter gates are required by FERC. Additional
scrutiny is placed on tainter gates by FERC after the Folsom Dam Failure. If Avista neglects to
address the conditons that FERC has put into place and expects from this project, in particular, we
will be out of regulatory compliance. (2) PERFORMANCE & CAPACITY fully functioning spillgates
are an integral part of a fully functioning dam. They maintain the forebay level which, in turn, helps
dictate the amount of power generated for our customers; they keep customers safe by controlling
the amount of water that flows downstream during normal operations and during flood events (3)
ASSET CONDITION The gates are original to the dam. The Noxon Spillgates are nearing the end of
their useful life as Avista transitions into the EIM market. EIM will require the spillgates to be used at
greater frequencies than they are today and with finer movements. The gate mechanisms can’t
support these types of and quanity of movements due to age, material, and design. This affects our
customers because Avista may not be able to provide power at the needed rate or quantity.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
See Section 1.1. Additionally, Avista has communicated to FERC that a gate project is forthcoming.
Should we neglect to move forward with this project, Avista would be out of regulatory compliance.
Requested Spend Amount $3,850,000
Requested Spend Time Period 6 years, 2019 - 2024
Requesting Organization/Department GPSS
Business Case Owner | Sponsor PJ Henscheid | Alexis Alexander
Sponsor Organization/Department GPSS
Phase Execution
Category Project
Driver Mandatory & Compliance
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 241 of 309
Noxon Rapids Spillgate Refurbishment
Business Case Justification Narrative Template Version: 04.21.2022 Page 3 of 8
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
(1) constructing a FERC approved design would remove Avista from any regulatory compliance lists
that we are on due to insufficiently strong spillgates; (2) The gates would operate such that the plant
operators could support the directives from the EIM market.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
• GPSS “G” Drive @ \\c01m114
o G:\Generation\401 Noxon Rapids\Projects\ER-4187 Spillgate
Refurbishment\40105196 Spillgate Remediation\05 Engr\05.12 -Studies
and Inspections
 LCI Seismic Analysis: this document discusses the seismicity of
the Noxon, Montana
 Strata Shear Wave Velocity Testing: this document provides
data showing how seismic waves move through the ground at
Noxon
 Stantec Structural Report: this document takes the seismic data
and the seismic analysis, applies it to the dam using models,
and discusses the failure points of the facility
 Schnable Seismic Hazard and Geophyiscal Report: This is
Avista’s Part 12 Inspector review of the LCI Seismic Analysis
o G:\Generation\' Hydro Plants\Noxon Rapids HED\Projects\2020
Spillgate Rehab\09 Submittals
 Draft Structural Report: this document updates the Stantec
Structural Report noted above using LCI Sesimic Analysis data
 Drafit Pier Analysis Technical Memo: this document
summarizes the structural analysis of the Noxon Dam spillway
piers to accommodate a cross-valley seismic event
 Draft Electrical Systems Evaluation Report: this document
reviews the feasibility of reusing the existing electrical
infrastructure
 Draft Gate Trunnion System Review: this document evaluates
the past use of the gates, future use of the gates, and the
existing conditions to help arrive at a recommendation for their
replacement.
 Draft Gate Hoist System Review: this document reviews the
existing hoist condition, expected lifting capacity, and potential
for upgrade and modernization
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
At minimum, the highlighted members require strengthening. Depending on the size of
an earthquake the FERC will require the gates to withstand, the entire gate could be
replaced as well as the associated mechanical and electrical gear. If the earthquake
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 242 of 309
Noxon Rapids Spillgate Refurbishment
Business Case Justification Narrative Template Version: 04.21.2022 Page 4 of 8
required by the FERC is large enough, it may require modifying the concrete Spillgate
piers. At this time however, the members will be only strengthened.

2. PROPOSAL AND RECOMMENDED SOLUTION
Continue on with the project. This is the best solution because we have promised the FERC
that we will mitigate structural issues on the spillgates and it will ensure the spillgates have a
long life once we have entered the EIM market.
Continuing forward with the proposed strengthening project of the identified weak members provides
confidence and our ability to meet all FERC design requirements for Tainter gates until such time as
we realize the full impacts of the seismicity at site.

Option Capital Cost Start Complete
Recommended: Strengthen the diagonal members
with bracing until such time as seismicity can
determine the best path forward for the gates
$3,850,000 01/2019 12/2024
Alternative 1: Rehab/Replace the Noxon Spillgates
following determination of seismicity needs
$24,900,000 01/2019 Unknown
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
o Engineering Analysis, see Section 1.5.1
o FERC reqirements
o Operational Data of the number of times the spillgates are used per year

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 243 of 309
Noxon Rapids Spillgate Refurbishment
Business Case Justification Narrative Template Version: 04.21.2022 Page 5 of 8
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
o Avista will receive upgraded spillgates, and associated appurtenances, once the project
is complete
o Newly renovated spillgates, once complete, should require less maintenance ethat 70
year old spillgates.
o New technology integrated into the project may require up-front training and
troubleshooting
The project is anticipating the following remaining costs:
2022 - $600,000
2023 - $3,100,000
2024 - $150,000

[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy
Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]

2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
o Upgraded Spillgates will support the EIM iniative be ensuring the gates are
functional to move as frequently as anticipated as part of Avista’s participation
in EIM
o Construction processes will make operating the all 8 spillgates impossible at
once, for rthe duration of construction.
o Upgraded spillgates will support operations O&M expendaratures year-over-
year

2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
o Not doing anything—this was never an option because working on the gates is
a FERC requirement
o Structural Reinforcement of select steel members—this was considered to be
an interim fix until the gates could be repair or replaced. The business unit
elected to not move forward with this because a larger gate project was on the
horizon.

2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
o Work is continuing forward to strengthen the gate members identified.
Construction activities will start in late 2022 and continue to mid to late 2024.
Likely a portion of the project will become used and useful in 2022 and 2023,
with the remainder in 2024. The means and methods and construction schedule
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 244 of 309
Noxon Rapids Spillgate Refurbishment
Business Case Justification Narrative Template Version: 04.21.2022 Page 6 of 8
have yet to be determined so exact timelines are unknown at this point in time.
It is anticvipated to perform work on Gate #5 in late 2022, Gates 6, 7, and 8 in
early 2023, and gates 1 through 4 in late 2023 and rolling into 2024.

2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
This project emphasizes: reliability, safety, and the customer (through the end result
of being able to support the EIM iniative.

2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
See Section 2.5.
Additionally We are prudently investing money to understand what type of
repair/repaclement/rehab is necessary. When we understand that, a second round
of prudency will be entered when the project and the project steering committee will
weigh the cost-benefits of each alternative.

2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
O Environmental
O Power Supply
O GPSS
O Supply Chain
O Exeternal Communications
O Asset Management
O Clark Fork Personnel

2.8.2 Identify any related Business Cases
No related business cases at this time

3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
STEERING COMMITTEE MEMBERS
O Bruce Howard
O Scott Kinney
O Alexis Alexander

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 245 of 309
Noxon Rapids Spillgate Refurbishment
Business Case Justification Narrative Template Version: 04.21.2022 Page 7 of 8
3.2 Provide and discuss the governance processes and people that will
provide oversight
O Dam Safety Team
O Scott Kinney
O Alexis Alexander
O Bruce Howard
The project will be led by the core project team. Any changes to scope, schedule
and budget will be submitted for approval to the steering committee and with the
respective cost thresholds as defined in the project charter.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
The project is utilizing the Project Change Log to track and manage all Project
Change Requests (PCR) associated with the delivery of the construction project.
The PCR describes the need for change, supplemental documentation, related
project artifacts, change order proposals, and any other pertinent information.
PCR’s are then signed for approval by the project approval thresholds, and then
processed against the project risk registry, and or contract amendment with the
contractor.

4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Noxon Rapids Spillgate
Refurbishment BCJN and agree with the approach it presents. Significant changes to this
will be coordinated with and approved by the undersigned or their designated
representatives.

Signature:

Date: 8.25.22
Print Name: PJ Henscheid
Title: Mgr, Civil and Mechanical
Engineering

Role: Business Case Owner

Signature: Date:
Print Name: Alexis Alexander
Title: Direector, GPSS
Role: Business Case Sponsor
9/2/2022
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 246 of 309
Noxon Rapids Spillgate Refurbishment
Business Case Justification Narrative Template Version: 04.21.2022 Page 8 of 8

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 247 of 309
Post Street Substation Crane Rehab
Business Case Justification Narrative Page 1 of 10
EXECUTIVE SUMMARY

The 35 Ton Niles Bridge Crane at the Post Street Substation is original to 1907 and
services the interior of the building. The primary function for this crane is to service the
Upper Falls and Monroe Street GSU’s, substation 115kv transformers, switchgear, and miscellaneous other substation equipment. It is a low frequency of use, high
consequence if unavailable when needed, piece of equipment.

The crane’s controls and electrical are mostly original and have degraded in capability
over time. Recent experience with the crane exhibited issues with controls and overheating/stalling with extended use. The current state of electrical components on this
crane are not capable of supporting the pick of a transformer without extensive
refurbishing. This negatively impacts the ability to respond to a failure in a critical
downtown substation and increases risk. The problem is aggravated by the lack of ability
to use a large enough standard mobile crane inside the building as an alternative.

The recommended solution includes a replacement of the existing crane electrical and
controls, refurbishment of the mechanical components, and replacement of the existing
hoist and trolley system with a modern arrangement. This approach is a modern in-kind
replacement of the current substation crane and would provide a lasting solution to meet current and future demands.

The estimated cost of the project is $2,134,000 in order to fully rehabilitate the crane. The
service code for this program is Electric Direct and the jurisdiction for the project is
Allocated North serving our electric customers in Washington and Idaho. Operating Post Street safely and reliably provides our customers with low cost, reliable power while
ensuring the region has the resources it needs for the Bulk Electric System (BES).

VERSION HISTORY
Version Author Description Date Notes
Draft Ryan Bean Initial draft of original business case 5/10/2022
1.0 Ryan Bean Update 8/2/2022
Updated based on
past actual costs and
equipment lead time.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 248 of 309
Post Street Substation Crane Rehab
Business Case Justification Narrative Page 2 of 10
GENERAL INFORMATION

1. BUSINESS PROBLEM

1.1 What is the current or potential problem that is being addressed?
The 35 Ton Niles Bridge Crane at the Post Street Substation is original to 1907
and it’s electrical and controls are beyond their useful life. The Primary function
for this crane is to service the Upper Falls and Monroe Street GSU’s, substation
115kv transformers, switchgear, and miscellaneous other substation equipment.
In it’s current state, it’s is unlikely the crane could support restoration efforts for a major equipment failure, thereby placing future repair or refurbishment
activities at risk. Restoring this cranes’ capability will enable response to a
failure in this critical downtown substation and prepare the site for future
projects.

1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer.
The driver for this business case is Failed Plant. The crane has exceeded it’s
useful life and is not likely able to perform the function needed to support the
substation and generator transformers. Post Street Substation supplies power
to a significant portion of downtown Spokane, as well as serving as a conduit
for Upper Falls and Monroe Street generating stations which supply year-round base load hydroelectric power. Continuing to operate Post Street safely and
reliably provides our customers with low cost, reliable power while ensuring the
region has the resources it needs for the Bulk Electric System (BES).

Requested Spend Amount $2,134,000
Requested Spend Time Period 3 years
Requesting Organization/Department C07/GPSS
Business Case Owner | Sponsor Ryan Bean | Alexis Alexander
Sponsor Organization/Department C07/GPSS
Phase Initiation
Category Project
Driver Failed Plant & Operations
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 249 of 309
Post Street Substation Crane Rehab
Business Case Justification Narrative Page 3 of 10
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
The current state of electrical components on this crane is unlikely to support the pick of a transformer without extensive refurbishing. This negatively impacts the ability to respond to a failure in this critical downtown substation and
increases the risk to our ability to reliably serve our customers. Without
mitigating the risk, the company would continue to be exposed to an uncertain
recovery for any major work needed at the facility.

While the Downtown Network has full redundancy, the substations that provide
that redundancy both have risks associated with them. The Metro Substation is
being replaced, but the new Metro Substation won’t be in place until at least
2026. The Post Street Substation (where the crane to be replaced is located) is the other substation servicing downtown Spokane. While not quite at the point of needing replacement, like Metro, the Post Street station is also dated. Having
a failure of a transformer at the Post Street Substation and not being able to
replace it would leave the downtown relying on Metro Substation, which is well
past its useful life, as evidenced by the approved business case to replace it.

1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the need listed above.
The measure of success would be in restoring the capabilities of the crane to
provide the lifting services needed at the location. This could be captured via a
successful post rehab load test, reduced O&M for crane repairs, and decreased
risk to future project schedules due to crane down time.

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem.
A crane assessment and evaluation was performed on Dec. 1, 2021 by
Simmers Crane. At a high level, the assessment found the electrical
components/controls for the bridge and trolley to be beyond service life
and at risk for failing the main functions of the crane. It was highly
recommended to replace all existing electrical controls on this crane.

The current mechanical condition of this crane appear to be acceptable,
though all of the hoist gearing is showing signs of misalignment wear and
further use of this crane could lead to extensive wear of mechanical parts.
Mechanical parts can still be sourced through Kone crane, though the price and availability of these parts is less than ideal and thus a new trolley and bridge drives is being recommended
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 250 of 309
Post Street Substation Crane Rehab
Business Case Justification Narrative Page 4 of 10
Please see also:
- Annual Crane Inspection Reports by PCI (2010-2021) with findings of
related deficiencies.
- 2002 Load Test

1.5.2 For asset replacement, include graphical or narrative representation
of metrics associated with the current condition of the asset that is
proposed for replacement.
The metric supporting the replacement of the current crane is that it is
beyond it’s useful life and is no longer able to perform the function
required. Major repairs to equipment may not be feasible and future
projects will be impacted without a crane readily available.

Option Capital Cost Start Complete
Alternative 1: Minimal Repairs $200,000 08 2022 6 2023
Alternative 2: In-Kind DC Control System $1,200,000 08 2022 12 2023
Alternative 3: Recommended Alternative
– New hoist/trolley and AC Controls on
Existing Bridge Frame
$2,134,000 08 2022 6 2024
Alternative 4: Install a New Crane $2,500,000 08 2022 6 2024
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.

A Crane Assessment and Evaluation was performed By Simmers Crane on Dec 1st 2021 to establish the existing condition and recommended actions. The report informed a high-level Alternatives Analysis performed by GPSS
Mechanical Engineering with budgetary cost estimates based on multiple
manufacturer’s input and past crane overhaul experience.

2.2 Discuss how the requested capital cost amount will be spent in the current year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.

The capital cost will be spread out over three years 2022-2024. 2022 will be primarily design and contracting totaling $250,000. 2023 would include
procurement, fabrication, and construction estimated at $1,730,000. 2023 will
include as builds and project closeout site totaling $154,000. This will not offset
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 251 of 309
Post Street Substation Crane Rehab
Business Case Justification Narrative Page 5 of 10
significant O&M charges because many of the crane components are beyond
service life and are unable to be maintained.

2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.

Fortunately, the Post Street Crane is not often used and it being unavailable will result in little impact to normal operations. If there is a transformer failure, the
primary business function impacted will be Generation and Substation response
time. 115 kV breaker failure, PT failure, underground line termination failure,
switchgear failure, and many other miscellaneous pieces would also be difficult
if not impossible to respond to. This could affect reliability of the 115 kV BES as well as other Generation and Distribution components.

Constructability details will need to be identified by the project team, which may
impact substation operations during the construction window. Any impacts to Substation and System Operations will be discussed and planned with the respective parties to mitigate impacts.

2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Alternative 1: Minimal Repairs
• Clean all electrical components before use
• polish conductor wire for trolley and bridge
• Replace all loose bolts noted in inspection
• Replace worn collector shoes on trolley
• Inspect and adjust brake on main hoist motor
• Mount a fan near resistor bank to keep cool
• Perform test crane pick to evaluate capacity
This crane is electrically outdated making most components obsolete or difficult to obtain and costs associated with making or attaining parts is unknown and a
risk to the budget. There are no guarantees that any of this work will make the
crane suitable for future use. There are also high safety risks associated with
this existing equipment as many electrical components are exposed and not
contained from accidental operator contact. The existing design of the crane also does not meet current OSHA and CMAA standards

Alternative 2: In-Kind DC Control System
• Full Non-Destructive Examination of all moving components
• New DC main feed rails down length of runway
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 252 of 309
Post Street Substation Crane Rehab
Business Case Justification Narrative Page 6 of 10
• New DC trolley festoon system
• Reuse existing trolley and bridge drive components
• Replace worn bushings on trolley/hoist
• Radio transmitter for wireless operation
• Misc. upgrades to meet current crane design and safety standards
The crane would be upgraded to a modernized DC system capable of running
the existing mechanical components and adding radio controls to crane. DC controls are more specialized engineering and there is a potential risk of
excessive cost associated. All warn bushings would need to be custom
manufactured and replacement costs will be substantial. There is a risk the NDE
results will require replacement of parts. Any part needing replaced has an
unknown cost associated. This option poses risk of using exiting components for long term crane use and does not provide extended service life equal to
options 4 and 5. Maintenance costs are also expected to be higher throughout
extended service life as compared to options 4 & 5 due to continued use of
bushings on rotating equipment and DC motors. The work and cost required to
replace worn items and correct the misalignment issues would be excessive and a new trolley would likely be more cost effective. It should be noted that the
trolley frame construction is mainly cast iron, and the equipment mounted
directly to cast iron framework. This construction is often difficult to upgrade with
any new equipment due to the inability to weld. This option is also not
recommended due to use of DC system in an AC supplied facility.

Alternative 3: Recommended Alternative – New Hoist/Trolley and AC Controls
on Existing Bridge Frame
• Upgrade power feed to 480 VAC
• New AC conductor bar down length of runway
• Modernize hoist, trolley and controls
• New AC trolley festoon system
• Radio transmitter for wireless operation
• New Bridge drive components
• Inspect Bridge wheels for reuse
• Misc. upgrades to meet current crane design and safety standards
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 253 of 309
Post Street Substation Crane Rehab
Business Case Justification Narrative Page 7 of 10
The new hoist, trolley and bridge drive would be vfd controlled for smooth and
safe operation of the crane. This option will also eliminate all outdated electrical
components and upgrade to a standard 480v system that is consistent with similar equipment at other Avista facilities and in the industry. This is the option that was chosen at both LF and LL facilities for crane upgrades and is the
recommended upgrade by GPSS engineering. Removing the old trolley and
installing the new trolley will pose some challenges and may require roof entry
of mobile crane as was done at LF. This option is beneficial for extended service life of the crane and to reduce maintenance costs as well. The extended service life will nearly match that of a new crane without the additional materials and
installation costs associated.

Alternative 4: Install a New Crane on Existing Runway
• Demo existing Niles Crane
• Runway structural engineering to confirm capacity with new crane
• Replace with new crane (end trucks, bridge girders, trolley, & hoist)
• Upgrade power feed to 480 VAC
• New AC conductor bar down length of runway
• New bridge walkway
• Radio transmitter for wireless operation
• New crane meets all updated codes and safety regulations
Removal of the existing crane structure and installation of a new crane structure poses higher risk and constructability than other options and will require multiple
overhead cranes and in-depth planning and engineering to accomplish. This
option would also have the potential to require longer outages for the 115v
portion of the sub near the demo and install. There are also unknowns associated with the structural engineering involved for the existing runway that is required under this option. A new crane would guarantee the longest extended
service life of any of the options presented. This option also has the possibility
of increasing the crane capacity to be able to lift a transformer without following
strict engineered pick procedures. The method for demo of old crane and install of new crane is still undefined and is expected to be the largest difference in cost between this option and option 3.

2.5 Include a timeline of when this work will be started and completed. Describe when the investments become used and useful to the customer. spend, and transfers to plant by year.

This project is expected to take 12 months starting in 2022 and ending in 2023.
The effort in 2022 will be devoted to design, equipment sourcing, and
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 254 of 309
Post Street Substation Crane Rehab
Business Case Justification Narrative Page 8 of 10
fabrication. The effort in 2023 will consist of site mobilization, construction, and
commissioning of the crane. The crane will not become used and useful until
successfully passing a load test during commissioning in 2023.

2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.

Operating Post Street Substation safely and reliably provides our customers with low cost, reliable power while ensuring the region has the resources it
needs for the Bulk Electric System. By taking care of this crane, we improve
our reliability and support our mission of improving our customer’s lives through
innovative energy solutions, which includes hydroelectric generation. By executing this project, we ensure that Post Street Sub, Upper Falls, and Monroe Street generation stations will continue to provide reliable service to our
downtown customers and mitigate risk to future projects and unplanned failures.

2.7 Include why the requested amount above is considered a prudent investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
Industrial cranes of this size and complexity fall into this range of cost based on manufacturers estimates and past in-house experience with crane rehabilitation. We are currently operating at risk at this location with being unable to respond
to a major equipment failure in a timely manner, thereby incurring lost generation
impacting customers.
A formal Project Manager will be assigned to a project of this size. The project will be managed within project management practices adopted by the Generation Production and Substation Support (GPSS) department. This
includes the creation of a Steering Committee and a formal Project Team. Once
the project is initiated, reporting on scope, schedule and cost will occur monthly.
Changes in scope, schedule, or cost will be surfaced by the Project Manager to the Steering Committee for governance. The Project Manager will manage the project through its conclusion.

2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
The primary stakeholders for this project are the Regional Plant Manager
and Operations crew on the Upper Spokane, GPSS Engineering, GPSS
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 255 of 309
Post Street Substation Crane Rehab
Business Case Justification Narrative Page 9 of 10
Construction and Maintenance, Substation Engineering, and System
Operations. Other stakeholders may be identified during project initiation.

2.8.2 Identify any related Business Cases
No current dependent Business Cases.
3.1 Steering Committee or Advisory Group Information
A formal Project Manager will be assigned to a project of this size. The project will be managed within project management practices adopted by the Generation Production and Substation Support (GPSS) department. A Steering
Committee will be formed for this project. The Project Manager will manage the
project through its conclusion.
3.2 Provide and discuss the governance processes and people that will provide oversight
Management of this project will include the creation of a Steering Committee
which will include managers representing the key stakeholders involved in this
project. The project will also be executed by a formal Project Team lead by the
Project Manager.
3.3 How will decision-making, prioritization, and change requests be documented and monitored
Once the project is initiated, reporting on scope, schedule and cost will occur
monthly. Changes in scope, schedule, or cost will be surfaced by the Project
Manager to the Steering Committee for governance.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 256 of 309
Post Street Substation Crane Rehab
Business Case Justification Narrative Page 10 of 10
The undersigned acknowledge they have reviewed the Post Street Substation
Crane Rehab business case and agree with the approach it presents. Significant
changes to this will be coordinated with and approved by the undersigned or their designated representatives.

Signature: Date:
Print Name: Ryan Bean
Title: Plant Manager, Upper Spokane
Role: Business Case Owner

Signature: Date:
Print Name: Alexis Alexander
Title: Director, GPSS
Role: Business Case Sponsor

Signature: Date:
Print Name: Glenn Madden
Title: Manager, Substation Engineering
Role: Steering/Advisory Review

Template Version: 05/28/2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 257 of 309
Regulating Hydro
Business Case Justification Narrative Page 1 of 8
EXECUTIVE SUMMARY

Avista’s regulating hydro plants are unique in that they have storage available in
their reservoirs. This enables these plants to have operational flexibility and are
operated to support energy supply, peaking power, provide continuous and
automatic adjustment of output to match the changing system loads, and other types
of services necessary to provide a stable electric grid and to maximize value to
Avista and its customers. These plants are the four largest hydro plants on Avista’s
system representing more than 950 MW of power and include Noxon Rapids and
Cabinet Gorge on the Clark Fork River in Montana and Idaho and Long Lake and
Little Falls on the Spokane River.
The operational availability for these generating units in these plants is paramount.
The service code for this program is Electric Direct and the jurisdiction for the
program is Allocated North serving our electric customers in Washington and Idaho.
The purpose of this program is to fund smaller capital expenditures and upgrades
that are required to maintain safe and reliable operation. Maintaining these plants
safely and reliably provides our customers with low cost, reliable power while
ensuring the region has the resources it needs for the Bulk Electric System (BES).
Projects completed under this program include replacement of failed equipment and
small capital upgrades to plant facilities. The business drivers for the projects in this
program is a combination of Asset Condition, Failed (or Failing) Plant, and
addressing operational deficiencies. Most of these projects are short in duration,
typically well within the budget year, and many are reactionary to plant operational
support issues. Without this funding source it will be difficult to resolve relatively
small projects concerning failed equipment and asset condition in a timely manner.
This will jeopardize plant availability and greatly impact the value to customers and
the stability of the grid.
Due to the age of the facilities more and more critical assets, support systems and
equipment are reaching the end of their useful life. This program is critical in
continuing to support asset management program lifecycle replacement schedules.
The annual cost of this program is variable and depends on discovery of unfavorable
asset condition and the unpredictability of equipment failures.

VERSION HISTORY
Version Author Description Date Notes
Draft Bob Weisbeck Initial draft of original business case 6/29/20
1.0 Bob Weisbeck Final signed business case 7/2/20
1.0 Bob Weisbeck Updated for 2022-2026 Capital Plan
2.0 Bob Weisbeck Updated for 2023-2027 Capital Plan 5/23/22

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 258 of 309
Regulating Hydro
Business Case Justification Narrative Page 2 of 8

GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
Due to the age and continuous use of the regulating hydro facilities, more and
more critical assets, support systems and equipment are reaching the end of their
useful life. In addition, it is difficult to predict failures and unscheduled problems
of operating hydroelectric generating facilities. This program is critical in
providing funding to support the replacement of critical assets and systems that
support the reliable operations of these critical facilities.
1.2 Discuss the major drivers of the business case
The major drivers for this business case are Asset Condition and Failed Plant.
This program provides funding for small capital projects that are required to
support the safe and reliable operation of these hydro facilities. The flexible
operations and generating capacity of these plants, maximize value for Avista
and our customers.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred.
Critical asset condition and failed equipment jeopardize the safe and reliable
operation of these generating facilities. If problems are not resolved in a timely
manner, the plant and plant personnel could be at risk and failed or unavailable
critical assets and systems will limit plant flexibility and availability. This could
have a substantial cost impact to Avista and our customers.
Without this funding source it will be difficult to resolve relatively small projects
concerning failed equipment and asset condition in a timely manner. This will
jeopardize plant availability and greatly impact the value to customers and the
stability of the grid.
Requested Spend Amount $15,750,000
Requested Spend Time Period 5 years
Requesting Organization/Department L07, D07, I07 / GPSS
Business Case Owner | Sponsor Bob Weisbeck | Alexis Alexander
Sponsor Organization/Department A07 / GPSS
Phase Initiation
Category Program
Driver Asset Condition / Failed Equipment
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 259 of 309
Regulating Hydro
Business Case Justification Narrative Page 3 of 8

1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
Plant reliability and availability is measured as well as the frequency and nature
of forced outages. These metrics will contribute to prioritizing the projects in this
program. Historically, this program has funded multiple projects per year which
contributed to high unit availability.

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem

The historical drivers of the projects selected to be funded by the program
are a mix of Asset Condition, approximately 87% and Failed Plant,
approximately 13%. Projects are typically completed in the calendar year.
The work is primarily performed in the 3rd and 4th quarters of the year when
outage in the Hydro Plants are scheduled, typically after run off in the rivers
has subsided.

1.5.2 For asset replacement, include graphical or narrative representation
of metrics associated with the current condition of the asset that is
proposed for replacement.
Being a program, this review will be performed on a project by project
basis. This decision will be made by the program Advisory Group.

Option Capital Cost Start Complete
Regulating Hydro Program $15,750,000 01/2022 12/2026
Individual Capital Projects $15,750,000 01/2022 12/2026
Perform O&M maintenance 0
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 260 of 309
Regulating Hydro
Business Case Justification Narrative Page 4 of 8
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Review of the program budget over the period of the last six years has revealed
a realistic annual budget is $3.15 Million.
The drivers of the projects selected to be funded by this program are mix Asset
Condition (approximately 87%) and Failed Plant (13%). Resolving issues
encountered in operating these plants in a timely manner benefits the customers
with providing safe, reliable, low cost power which supports the needs of Bulk
Electric System and provides value to Avista and our customers.

2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.

The annual budget program, based on review of the past six years, is
approximately $3.15 million. Projects with lower risk will be delayed through this
period. The projects in this program typically take place during the outages
which are in the summer and fall of each year. Most of the capital is deployed
in the 3rd and 4th quarter of each year.

If capital funds were not available for the projects in this program, reliability of
the plant would decrease, and more O&M would need to be performed to repair
aging equipment instead of replacement. This would be an unacceptable and
substantial increase in the O&M expenditures.

2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.

These projects vary in size and support needed based on the requests from the
department and from key stakeholders. The larger projects require formal
project management with a broader stakeholder team. Medium to small projects
can be implemented by a project engineer or project coordinator and many
cases can be handled by contractors managed by the regional personnel. All
these projects are prioritized and coordinated by the broader support team.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 261 of 309
Regulating Hydro
Business Case Justification Narrative Page 5 of 8
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
One alternative would be to create business cases using the business case
template and process for each of these small projects. There are typically 40-
50 projects a year funded by the program. This would overload the Capital
Budget Process with small to medium projects whose governance can be
effectively handled by the hydro organization. These projects are specific to
these plants and the leadership in hydro operations understand the best the
nature and context of these projects.
These projects are somewhat unpredictable. It would be difficult to forecast
unforeseen events such as equipment failures and identify critical asset
condition that could effectively be put in the annual capital plan.
Another alternative would be to attempt to repair this equipment instead of
replacing critical assets at the end of their lifecycle. This will be unacceptably
expensive and older equipment will become more and more unreliable until it
becomes obsolete. Operating in a run-to-failure mode is proven to be an
unsuccessful approach and subjects Avista and its customers to unacceptable
risk.

2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
spend, and transfers to plant by year.

The projects in this program typically take place during the outages for the Hydro
Plants which are typically in the summer and fall of each year. Some projects
may have the ability to be performed in the first two quarters of the year but most
of the capital is deployed in the 3rd and 4th quarter of each year. Work performed
in and around the dams that require outages typically is safer and more cost
effective after run off has occurred in the rivers.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.

The purpose of this program is to provide funding for small to medium size
projects with the objective of keeping our hydroelectric plants reliable and
available. These plants affordably support the power needs of our company
and our customers. By taking care of these plants we support our mission of
improving our customer’s lives through innovative energy solutions which
includes hydroelectric generation. By executing the projects funded by the
program, we ensure that hydro facilities are performing at a high level and
serving our customers with affordable and reliable energy.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 262 of 309
Regulating Hydro
Business Case Justification Narrative Page 6 of 8
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
Review of the program budget has revealed that a realistic annual budget is $3.15
Million.
The drivers of the projects selected to be funded by this program are mix Asset
Condition (approximately 87%) and Failed Plant (13%). Resolving issues encountered
in operating these plants in a timely manner benefits the customers with providing safe,
reliable, low cost power which supports the needs of Bulk Electric System and provides
value to Avista and our customers.

2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case

The list of primary customers and stakeholders includes: GPSS, Environmental
Resources, Power Supply, Systems Operations, ET, and electric customers in
Washington and Idaho.

2.8.2 Identify any related Business Cases

3.1 Advisory Group Information
The Advisory Group for this program consists of the four regional Hydro Managers and
the Sr Manager of Hydro Operations and Maintenance.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 263 of 309
Regulating Hydro
Business Case Justification Narrative Page 7 of 8
3.2 Provide and discuss the governance processes and people that will
provide oversight
Projects are proposed through various organizations in Generation Production and
Substation Support (GPSS) and through key stakeholder such as Environmental
Resources, Dam Safety, and Safety and Security. The projects are vetted by the Hydro
Advisory Group. With the assistance of Operations, Construction and Maintenance
and Engineering, projects are evaluated to determine available options, confirm
prudency, and bring potential solutions forward.
This same vetting process is followed for emergency projects and may include other
key stakeholders. Over the course of the year, the program is actively managed by the
Sr. Manager of Hydro Operations, with the assistance of the Advisory Group. This
includes monthly analysis of cost and project progress and reporting of expected spend.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
Each project request will be evaluated by the Advisory Group which will include
the scope, cost and risk associated with the project. The project will be
evaluated based on the impact or potential impact of the operation of the
Regulating Hydro plants. The selection and approval of the project will be based
on the experience and consensus of the Advisory Group.
Depending on the size of the project, a Project Manager or Project Coordinator
may be assigned. In this case, the project management process will be followed
for reporting and identifying and executing change orders. Smaller projects will
have a point of contact and financials will be review on a monthly basis by the
Advisory Group.

The undersigned acknowledge they have reviewed the Regulating Hydro Program
business case and agree with the approach it presents. Significant changes to this
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 264 of 309
Regulating Hydro
Business Case Justification Narrative Page 8 of 8
will be coordinated with and approved by the undersigned or their designated
representatives.

Signature: Date:
Print Name:
Title:
Role: Business Case Owner

Signature: Date:
Print Name:
Title:
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
05-23-2022
Bob Weisbeck
Manager, Hydro Ops and Maintenance
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 265 of 309
Upper Falls Trash Rake Replacement
Business Case Justification Narrative Template Version: 04.21.2022 Page 1 of 8
EXECUTIVE SUMMARY
The existing trash rake at Upper Falls is an articulating arm Atlas Polar device. The trash
rake has, since its installation, presented an environmental risk due to the hydraulic system that utilizes to function. When in use, the hydraulic system is suspended over the Upper Fall unit intake and the Spokane River. Should a hydraulic line fail during raking
operation, some amount of hydraulic fluid would end up in the river, leading to an
environmental cleanup exercise. While the rake is in its parked position, the hydraulic
system is in very close proximity to the river and poses a threat to leaking. The current
trash rake is undersized, leading to issues during raking operations. Often, the rake stalls
out mid-operation due to the weight of accumulated debris it is trying to recover. The rake
is also limited in its ability to lift logs and tress which can accumulate in front of the rakes,
leading to potential personnel safety issues with operators being required to cut up the
logs and trees while in very close proximity to the river’s edge. Often times this is an operator leaning out over the handrail to address the problem. A safety action item was identified in 2016 related to the conveyor system that the trash rake utilizes to accumulate
cleaned debris into a dumpster. This conveyor system, at the time posed a personnel
safety threat due to its open operating nature. The risk of someone becoming entangled
in the operating conveyor system drove a safety switch to be installed. The recommended alternative is to replace the trash rake with an appropriately sized
system that will allow full reach of the intake racks and accommodate large sized trees
and logs to be removed from the river. This alternative would either replace the conveyor
belt system with a new and safer alternative type of debris conveyance system or would remove that system entirely. This alternative would likely still utilize hydraulics to function, however, a robust containment system would be required and modern control system can
detect and shut off the system when a leak is identified, often resulting in very small
amount of leakage reaching the waters surface. This alternative is likely to be a packaged
device with modern controls and electrical systems. The recommended solution was reviewed by GPSS Engineering and approved by GPSS Management.

VERSION HISTORY
Version Author Description Date Notes
1.0 PJ Henscheid Format existing BC into exec summary 7.2.20 5-year Capital Planning
Process
2.0 PJ Henscheid Completion of full BCJN document 8.4.20 5-year Capital Planning
Process
3.0 PJ Henscheid Updated to 2022 template and modified
budget to align with improved estimates 8.24.22

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 266 of 309
Upper Falls Trash Rake Replacement
Business Case Justification Narrative Template Version: 04.21.2022 Page 2 of 8

GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
The major driver for this business case is asset condition. The existing trash rake at
Upper Falls is an articulating arm Atlas Polar device.
The trash rake has, since its installation, presented an environmental risk due to the hydraulic system that utilizes to function. When in use, the hydraulic system is
suspended over the Upper Fall unit intake and the Spokane River. Should a
hydraulic line fail during raking operation, some amount of hydraulic fluid would end
up in the river, leading to an environmental cleanup exercise. While the rake is in its parked position, the hydraulic system is in very close proximity to the river and poses a threat to leaking.
The current trash rake is undersized, leading to issues during raking operations.
Often, the rake stalls out mid-operation due to the weight of accumulated debris it
is trying to recover. The rake is also limited in its ability to lift logs and tress which can accumulate in front of the rakes, leading to potential personnel safety issues with operators being required to cut up the logs and trees while in very close
proximity to the river’s edge. Often times this is an operator leaning out over the
handrail to address the problem.
A safety action item was identified in 2016 related to the conveyor system that the
trash rake utilizes to accumulate cleaned debris into a dumpster. This conveyor system, at the time posed a personnel safety threat due to its open operating nature.
The risk of someone becoming entangled in the operating conveyor system drove
a safety switch to be installed.
Requested Spend Amount $1,500,000
Requested Spend Time Period 2 years, 2022 – 2023
Requesting Organization/Department GPSS
Business Case Owner | Sponsor PJ Henscheid | Alexis Alexander
Sponsor Organization/Department GPSS
Phase Execution
Category Project
Driver Asset Condition
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 267 of 309
Upper Falls Trash Rake Replacement
Business Case Justification Narrative Template Version: 04.21.2022 Page 3 of 8

1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
The major driver for this business case is Asset Condition. Having an effective and reliable trash cleaning device is imperative for the continued efficient operation of our Hydro generating units. Replacing this trash rake will not only provide for the
safety of our operations staff, but will encourage the reliable operation of Upper Falls
HED which contributes to the successful implemtnation of our Spokane River
license.

1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
This work is needed to address the personnel safety issues related to the converyor system of the existing trash rake as well as address the potential environmental risks present with the existing design. Both of these risks remain if this work is
deferred or not performed.

1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
Continued effective operation of upper falls hed will signify successful implementation of this project, but more importantly addressing the personnel safty risks as well and the environmental risks present in the current design will determine
project success.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
[List the location of any supplemental information; do not attach]
1.5.2 For asset replacement, include graphical or narrative representation of metrics associated with the current condition of the asset that is proposed for
replacement.
Knuckle Boom Marginal 4.67
Trashrake Marginal 4.00
The above table is from the Net Condition Index and Rating summary. This information was compiled during the maintenance assessment of all Hydro assets performed in
2018. As shown, the condition of both the knuckle boom and trash rake are currently
marginal, and do take into account the safety and environmental risks.

2. PROPOSAL AND RECOMMENDED SOLUTION
The recommended alternative is to replace the trash rake with an appropriately sized
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 268 of 309
Upper Falls Trash Rake Replacement
Business Case Justification Narrative Template Version: 04.21.2022 Page 4 of 8
system that will allow full reach of the intake racks and accommodate large sized
trees and logs to be removed from the river. This alternative would either replace the conveyor belt system with a new and safer alternative type of debris conveyance
system or would remove that system entirely. This alternative would likely still utilize
hydraulics to function, however, a robust containment system would be required and
modern control system can detect and shut off the system when a leak is identified,
often resulting in very small amount of leakage reaching the waters surface. This alternative is likely to be a packaged device with modern controls and electrical
systems.

This alternative would likely include some amount of concrete work to facilitate and
support the installation of a new trash rake. This could also include some concrete demolition and removal and replacement of embedded components.

This alternative would allow for reliable and safe operation and cleaning of the intake
racks at Upper Falls, and would take into full consideration all personnel safety issues
highlighted to date, as well as identify and address other possible safety issues.
This alternative is anticipated to begin in 2023, with an engineering assessment
design starting that year. Construction could start as soon as early fall 2024. The
project is anticipated to be transferred to plant sometime in 2025.

Option Capital Cost Start Complete
Repace Upper Falls Trash Rake $1,500,000 01/2022 12/2023
Alt 1: Do Nothing $0 NA NA

2.1 Describe what metrics, data, analysis or information was considered when preparing this capital request.
Data compiled from the replacement of the trash rake at Nine Mile in 2018 helped to
inform this capital request. It is anticipated the new trash rake at Upper Falls could
be very similar in nature, both in scope of supply and operationally, to what was installed at Nine Mile.

2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include any known or estimated reductions to O&M as a result of this investment. Some O&M cost savings are anticipated to be realized as a result of this project in
reducing the amount of repairs and maintenance need to be performed on the trash
rake. Also, the intent of the new design would allow for a safe and effective one
person cleaning operations instead of the current practice of two operations personnel.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 269 of 309
Upper Falls Trash Rake Replacement
Business Case Justification Narrative Template Version: 04.21.2022 Page 5 of 8
The project is anticipating the following costs:
2022 - $300,000
2023 - $1,200,000

[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy
Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]

2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
Operations and Power Supply will be impacted by this business case during
implementation. Upper Falls generating unit will be required to be off-line during the totality of construction. This will affect plant operations and power supply, and will
require all river flows to pass through the Control Works spillgates. The duration of
construction activities is unknown at this time.

2.4 Discuss the alternatives that were considered and any tangible risks and mitigation strategies for each alternative.

Alternative 1 – Do Nothing
This alternative would not allow for improving the functionality of the trash
rake nor remove any of the safety risks associated with the existing rake.
The major risk associated with this alternative is the unreliable operation and
personnel safety and environmental risks associated with the existing
design. This alternative would continue to affect the Operation and
Maintenance budget as repairs continue to be an issue and the equipment
continue to age. Downtime for the plant could likely increase if outages of the trash rack increase due to age.

2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer. Design efforts kicked off in 2022, with vendor selection, site visits and design analysis. Procurement also started in 2022 with the trash rake anticipated to
be delivered in 2023. The majority of the scope of supply is anticipated to be
delivered in early 2023, with construction activities starting as early as June
of 2023 – following spring run-off. Construction is anticipated to take most of the summer and fall of 2023, with an anticipated transfer to plant of the entire project of the end of 2023.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 270 of 309
Upper Falls Trash Rake Replacement
Business Case Justification Narrative Template Version: 04.21.2022 Page 6 of 8
2.6 Discuss how the proposed investment aligns with strategic vision, goals, objectives and mission statement of the organization.
The delivery of this project is highly important in the sustainability and operations of
our Spokane river facilities and operating them safely and responsibly. The project
will focus of the people responsible the delivering with a strong emphasis on
performance. This nature of the project demands a collaborative environment with
the wide array of key stakeholder groups. This will address personnel safety issues, environmental concerns, and unit reliability all at the same time.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed and re-evaluated throughout the project
The project budget and total cost will be regularly reviewed with the project
steering committee, as well as, receive approvals as described below for any
changes in scope and cost. Prudency is also measured by remaining in
compliance the FERC License such that we can continue to operate Spokane
River dams for the benefit of our customers and company.

2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
- GPSS Engineering; Civil, Mechanical, Electrical and Controls
- Hydro Operations
- Environmental, Permitting, and Licensing
- Master Scheduler
- Asset Management - Project Accounting, Finance, and Rates
- Supply Chain and Legal
- Corporate Communications
- Construction Inspection and Project Management

2.8.2 Identify any related Business Cases
This project has no other relevant business cases at this time.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 271 of 309
Upper Falls Trash Rake Replacement
Business Case Justification Narrative Template Version: 04.21.2022 Page 7 of 8
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
The advisory group for this project will consist of members from the Generation Production and Substation Support department, Power Supply, and the Environmental department. Specific individuals of the steering committee will be
selected at a later date by the GPSS leadership team. Advisors are provided with
monthly project status reports but, are only convened in the event of a necessary
decision point.

3.2 Provide and discuss the governance processes and people that will
provide oversight
The project will be led by the core project team. Any changes to scope, schedule
and budget will be submitted for approval to the steering committee
3.3 How will decision-making, prioritization, and change requests be documented and monitored
The projectis anticipated to utilize the Project Change Log to track and manage all
Project Change Requests (PCR) associated with the delivery of the construction
project. The PCR describes the need for change, supplemental documentation, related project artifacts, change order proposals, and any other pertinent
information. PCR’s are then signed for approval by the project approval thresholds,
and then processed against the project risk registry, and or contract amendment
with the contractor.
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Upper Falls Trash Rake Replacement
and agree with the approach it presents. Significant changes to this will be coordinated with
and approved by the undersigned or their designated representatives.

Signature:

Date: 8.24.22
Print Name: PJ Henscheid
Title: Mgr, Civil and Mechanical
Engineering

Role: Business Case Owner

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 272 of 309
Upper Falls Trash Rake Replacement
Business Case Justification Narrative Template Version: 04.21.2022 Page 8 of 8
Signature: Date:
Print Name: Alexis Alexander
Title: Director, GPSS
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 273 of 309
Energy Imbalance Market
Business Case Justification Narrative Page 1 of 12
EXECUTIVE SUMMARY
In an effort to continue as a low cost, customer-focused energy service provider, Avista signed
an Implementation Agreement on April 25, 2019 with the California Independent System
Operator (CAISO) to join the Western Energy Imbalance Market (EIM) by April 2022. The
Western EIM is a real-time, intra-hour energy market operated by CAISO that facilitates
regional resource dispatch on a five minute basis to dispatch the lowest cost resources across
the entire market footprint, while balancing in-hour load and resource obligations. This market
allows participants to lower energy costs by either dispatching less expensive resources to meet
load obligations, or by increasing revenue through the bidding of excess energy into the
market. By the time Avista joins, more than 82% of the Western Interconnection load will be
transacting in the EIM. As such, the liquidity of the hourly bi-lateral market Avista has
traditionally transacted in will be significantly impacted because market rules require EIM
participants to determine their resource schedules well in advance of the upcoming hour. As
such, non-EIM participants will have less counterparties to transact with close to the operating
hour. In addition, as renewable portfolios are increasingly mandated, Avista will need the
market to ease the financial pressure of integrating renewable resources, while maintaining
reliability.

In July 2020, in partnership with CAISO and the Bonneville Power Administration (BPA), Avista
changed their entry date to March 2022, to align with BPA and Tacoma Power. This decision
was made in an effort to coordinate the testing phases and go-live operations amongst
northwest entities for a smoother market entry transition.

Avista will need to implement a variety of EIM software solutions, perform metering upgrades
at a majority of its generation and substation interconnection sites, and install generation
control systems. The original estimates described in the EIM Program Charter reflected $18.1M,
with $4.5M planned in contingency, for a total estimated capital spend of $22.6M. The Charter
also outlined $2.9M in implementation expense for a total Program implementation cost
estimate of $26.6M and $3.5-$4M in on-going annual expense. In October 2020, cost estimates
were updated in the Program Scope document, reflecting $24.1M with $2.6M planned in
contingency, for a total estimated capital spend of $26.7M. The Charter also outlined
implementation expense estimates at $5.4M for a total Program implementation cost estimate
of $32.1M and an on-going annual expense estimate of $3.9M.

The Program implementation effort began in 2019 and will continue through March 2022, with
warranty and closing activities through summer 2022. The CAISO allows Entities to join the
market annually in April, with a fixed CAISO-set schedule for testing phases and market go-live.
If Avista does not meet the planned go-live date, Avista will need to wait until April 2023 to join
the market. Missing the go-live date will put Avista at risk for maintaining reliable service to our
customers, providing energy services at the lowest costs, integrating renewable energy at the
lowest costs and hindering de-carbonization efforts.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 274 of 309
Energy Imbalance Market
Business Case Justification Narrative Page 2 of 12
The work in the EIM Business Case (BC) will benefit electric customers in Washington and Idaho
while the network improvements will benefit gas and electric customers in Washington, Idaho
and Oregon.
VERSION HISTORY
Version Author Description Date Notes
1.0 Kelly Dengel Original Business Case Template 4/29/2019
2.0 Kelly Dengel Updated Business Case Template 7/31/2020 Based on Charter Document
3.0 Kelly Dengel Updated Business Case Template 12/17/2020 Based on Scope Document

GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
Avista, and other utilities across the northwest, have traditionally operated in a bilateral market.
As more utilities join an organized market, market liquidity will be impacted by reducing the
number of available bi-lateral trading partners to conduct near term daily energy transactions.
This puts Avista at risk for higher market prices and reliability issues if energy can’t be procured
from the bi-lateral market during stressed conditions, such as the loss of an Avista generating
facility. Avista’s resource mix continues to change with the inclusion of additional renewable
resources to meet both internal clean energy goals and state policy requirements. As additional
renewable energy integrates into the Avista portfolio, it becomes more expensive to manage and
follow the variable nature of these resources. The EIM provides a more economic means to
manage renewable resource variability.
In monitoring this risk and bilateral market shift, Avista has progressively monitored organized
energy market activity within the west including the CAISO EIM and the possible formation of the
Requested Spend Amount $26.7M
Requested Spend Time Period 3 Years – 2019 through 2022
Requesting Organization/Department Power Supply
Business Case Owner | Sponsor Kelly Dengel | Scott Kinney & Mike Magruder
Sponsor Organization/Department Power Supply | System Operations
Phase Execution
Category Program
Driver Performance & Capacity
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 275 of 309
Energy Imbalance Market
Business Case Justification Narrative Page 3 of 12
Mountain West Transmission Group (MWTG). In April 2018, the MWTG initiative was deferred,
and in December 2018 Avista decided to pursue entry to the Western EIM. Avista signed an EIM
Implementation Agreement with the CAISO on April 25, 2019 to join the market in April 2022. In
July 2020, in partnership with CAISO and the Bonneville Power Administration (BPA), Avista
changed their entry date to March 2022, to align with BPA and Tacoma Power. This decision was
made in an effort to coordinate the testing phases and go-live operations amongst northwest
entities for a smoother market entry transition.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
The major drivers influencing Avista’s decision to join the market centered on reliability, the
integration of renewable resources and a desire to adhere to clean energy goals.
The CAISO EIM is an in-hour economic based regional resource dispatch program that allows
participants to maintain system reliability and lower energy costs by either dispatching less
expensive resources to meet load obligations, or increase revenue through the bidding of excess
energy into the market. The EIM dispatches the most economic resource across the entire market
footprint based on bid prices to balance in-hour load and generation, resulting in lower overall
dispatch cost for each individual participant. The EIM also lowers the amount of on-line
regulation that each utility holds in excess every hour to make up the error between the
forecasted load and resource plans, and what actually occurs during the operating hour. The
reduced regulation can then be monetized creating additional revenue.
Another driver for joining the EIM is the integration of additional renewable resources in the
Avista Balancing Authority Area (BAA). Renewable generation requires additional regulation and
load following to back up the intermittency of the resource. There is a tipping point where
Avista’s existing hydro flexibility can’t sufficiently or economically supply the required load
following for the amount of renewable resources integrated into the Avista BAA. The EIM allows
for the expanded integration of renewable resources by providing a cost effective, reliable
market backstop to balance intermittent resources. Currently Avista has only a single 100 MW
wind facility and a 20 MW solar facility within its BAA, so there is adequate hydro flexibility to
follow these plants. Recently Avista signed a new 20 year Power Purchase Agreement with
Clearway Energy for 145 MW of wind starting in the fall of 2020. In addition there are multiple
third-party independent power producers in the Avista transmission interconnection queue that
are exploring integration into the Avista BAA, including projects that meet the Public Utility
Regulatory Policies Act requirements to be considered as a qualifying resource.
In April of 2019, Washington State passed clean energy legislation that will drive additional
renewable resources to be built in Avista’s BAA. Finally, Avista recently announced its own clean
energy goals that will transition our resource mix to 100 percent clean by 2045. Any additional
renewable resource integrated in Avista’s service territory results in a reduction of hydro
flexibility to follow these variable resources, and the EIM is the most efficient and cost effective
way to provide the required flexible ramping capability.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 276 of 309
Energy Imbalance Market
Business Case Justification Narrative Page 4 of 12
1.3 Identify why this work is needed now and what risks there are if not approved or is deferred
Entities typically announce their intent to join the market at least two years prior to go-live, while
the CAISO-driven implementation schedule is 18 months for market integration. Avista has given
itself a little over 2.5 years to prepare for market entry, as there is a substantial body of technical
work, physical construction work and business process design Avista must complete. This
extended timeline allows Avista to implement five new software applications, conduct upgrades
to existing software, and perform generation metering and control upgrades, interconnection
metering upgrades at substations and associated network infrastructure upgrades. Throughout
the implementation, Avista will rely on Utilicast, their consultant system integrator, to provide
market education and expertise in preparing the company for successful market participation.

Several northwest utilities, (PacifiCorp, Portland General Electric (PGE), Puget Sound Energy,
Idaho Power Company (IPC), Northwestern, Seattle City Light and BPA) along with other western
utilities, have either already joined the CAISO EIM or announced they will join in the near future.
When BPA joins the Western EIM in March 2022, more than 80 percent of the load in the Western
Interconnection will be participating in the market. This shift in market participation will impact
daily market liquidity by reducing the number of available bi-lateral trading partners to conduct
near term daily energy transactions. The risk of limited trading partners could drive daily market
prices higher and/or cause reliability issues for Avista if energy can’t be procured from the bi -
lateral market during stressed conditions, such as the loss of an Avista generating facility.

1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the need listed above.
CAISO publishes a quarterly benefit report, which represents a calculation of each Entities’
market benefits. This report will be used in part to reflect Avista’s EIM benefits, and determine
the EIM Business Case investment payback period. Avista will also develop an internal benefit
report, which will include considerations for hydro bidding and Avista specific operational factors
that may not be adequately represented in CAISO’s benefit calculation. These two items
combined will help Avista determine the financial investment return.

Prior to signing the CAISO EIM Implementation agreement in April 2019, Avista hired Energy and
Environmental Economics (E3) to conduct an EIM benefit assessment in the fall of 2017. E3 has
conducted similar benefit assessments for several other utilities to help understand the potential
value of EIM participation. The E3 assessment estimated that Avista could see a range of annual
benefits from $2 to $12 million from EIM participation.

There are four main study assumptions that result in the wide range of potential EIM benefits:
the amount of flexible hydro Avista bids into the market, the amount of transmission made
available for market transactions, the amount of renewable generation that is integrated into the
Avista BAA, and the assumed EIM price volatility. Using Avista’s best estimates for these critical
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 277 of 309
Energy Imbalance Market
Business Case Justification Narrative Page 5 of 12
study assumptions, Avista anticipates EIM annual benefits to be close to $6 million, with potential
for benefits to move closer to the upper end of the study range depending upon observed market
price volatility. Recent market price volatility experienced in 2018 significantly increased the
benefits of current market participants. Both IPC and PGE achieved EIM benefits in 2018 that
were over five times their anticipated benefits calculated by E3 studies. Avista’s resource mix and
transmission connection to other EIM participants most closely matches IPC and PGE. Therefore
Avista may achieve similar elevated EIM benefits during times of high market price volatility.

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
Additional Program detail is provided in the EIM Program Initiation Charter dated May 17, 2019
and the EIM Program Scope Document dated October, 29, 2020. Both are posted to the EIM
SharePoint site.
1.5.2 For asset replacement, include graphical or narrative representation of metrics associated with the current condition of the asset that is proposed for replacement.
Across a majority of the generation and substation sites, Avista has relied on non-revenue quality
meters with no ability to securely retrieve 5-minute revenue quality interval meter data required
for market participation. Most of Avista’s generation sites did not have revenue class Current
Transformers (CTs) or Potential Transformers (PTs) that allow for accurately measuring
generation output. Avista also has very limited Automated Generation Control (AGC) systems and
associated Programmable Logic Control (PLC) at its generation plants – both of which are
required for a resource to receive and follow a market dispatch signal. Although there is a
communication network presence at most of these generation sites, not all generation meters
are capable of connecting to the network for retrieval of 5-minute interval data. However, the
current state of Avista’s meters, generation controls and associated network connectivity was
acceptable, as Avista traditionally operated in a bi-lateral hourly market. The generation meters
will be replaced with a SEL-735 meter, or a locations where the SEL-735 already exists, the meter
will be reprogrammed to collect 5-minute reads.

Throughout substation interconnection sites, Avista does meet the revenue quality meter
requirement with JEMStar meters and accurate CTs/PTs. Although Avista considered
reprograming these meters to collect 5-minute interval data with an associated memory
upgrade, these meters are at least 12 years old, require dial up communications to retrieve
interval data and are unable to connect via Internet Protocol (IP) communications. Considering
the age of the meters and the fact that Avista should not rely on dial up communications alone,
the decision was made to replace the meters with a SEL-735 meter, capable of 5-minute interval
data and multiple connectivity options.

Due to limited field support of dial up communications and lack of monitoring capabilities, Avista
decided to replace dial up communications in favor of IP communications installations wherever
cellular installations are feasible – this aligns with Avista’s preferred communication protocol and
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 278 of 309
Energy Imbalance Market
Business Case Justification Narrative Page 6 of 12
long-term operational plan. For the purposes of EIM, the IP communications migration will be
limited to MV-90, engineering access, and metering communications, but eventually could
include migration of SCADA as part of a future project if the new IP communications circuits are
deemed reliable. Migration to IP communications for SCADA and metering has been a long-term
focus and evolution for Avista. Avista does collect hourly interchange meter data, but it’s done
at most substations by non-revenue meters with varying capabilities, with various network
protocols, manual processes and supplemented with information from PI (Plant Information) and
SCADA averages. This process and the associated data are not scalable or reliable for accurate 5-
minute interval EIM metering and settlements.

Option Capital Cost Start Complete
CAISO Western Energy Imbalance Market $26.7M 05/2019 06/2022
Do Nothing $0 N/A N/A
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Reference key points from external documentation, list any addendums, attachments etc.

Avista developed its initial EIM implementation estimate with help from Utilicast who has aided
several other Utilities prepare for market operations. Avista hired Utilicast to perform a
technology assessment, a meter and controls assessment, and develop an overall cost
assessment in 2018. Avista recognizes that the EIM project implementation cost estimate is a
working estimate and will evolve as the Company learns more about the specific CAISO EIM
requirements, determines the capability of its existing equipment, completes the preliminary
design of required upgrades and selects its market application vendors.

After the Utilicast assessments were complete, Avista used the information to reexamine the
work load and design requirements for facility upgrades including meters, generation controls,
and communication networks. Avista also develop a project schedule, project structure and
preliminary resource plan. This updated information was used to develop the EIM Program
Initiation Charter in May of 2019 and inform the EIM Business Case narrative. The Program Scope
document approved in October 2020 provided further cost estimate updates base on completing
initial project designs and installations and reevaluating employee resource needs. Avista
recognizes the cost and preparation for EIM entry is significant so it has been diligent in its
structured approach to estimate project costs and keep actual costs under control. The Company
reached out to multiple existing EIM participating entities to acquire best practices based on their
approach and experience. Avista chose to hire Utilicast to leverage its EIM operational and
integration expertise in lieu of attempting an Avista-guided implementation.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 279 of 309
Energy Imbalance Market
Business Case Justification Narrative Page 7 of 12
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy
Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]

The EIM Program is a multi-year program affecting Generation Production & Substation Support,
Power Supply, Transmission System Operations, Substation, Enterprise Technology, Accounting
and SCADA. The below tables represents the anticipated capital allocation request per year based
on the Program Scope estimates and a summary of what projects or deliverables will be
addressed.

BC Year Capital Request Projects/Deliverables
Total $26,700,000

In preparation for Avista to enter the Western EIM, the discussion of the roles and teams required
for a successful market entry and on-going operations was imperative. As described in the
executive-approved EIM Human Resource Plan of May 2020, 17 incremental full-time employees
were identified for the program implementation and the post-implementation phases. This
document includes justification for each position, an explanation of job functions as they relate
to EIM and associated risks if the position isn’t approved for hire. After reviewing the program
implementation schedule, and accommodating a timeline for resources to participate in the
software implementation phases, a preferred hire date was developed. This preferred hire date,
along with an estimation of time allocated to EIM capital activities and expense activities,
provided input for a 2020-2023 annual financial estimate, with 2023 representing a full-year of
operations and maintenance (O&M) expense activities.

In 2018, Avista originally estimated annual O&M expense at $3.5 - $4.0 million, with $2.5 million
attributed to the original labor estimate of 11-13 incremental EIM FTEs. The revised estimate of
17 EIM FTEs, as described in the EIM Human Resource Plan, increases the annual labor estimate
to $3.2 million (system loaded) and the total estimated annual expense to $3.9M. The need for
the additional 4 FTEs (17 vs. 13), was determined through staffing conversations with other EIM
entities, who indicated lean staffing levels at the time of market entry have hindered operational
performance. Avista believes the 17 FTEs represents a mature workforce needed to fully support
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 280 of 309
Energy Imbalance Market
Business Case Justification Narrative Page 8 of 12
EIM operations at market entry. Any additional EIM roles Avista may need will be assessed after
Avista has gained experience operating in the market.

In August 2020, prior to incorporating the updated EIM Human Resource Plan cost estimates in
the Scope Document estimates, the FTE cost estimates were reviewed in light of the EIM Charter
estimates and reductions were made. Reductions were also made to reflect 2020 hiring delays
and the postponement of two positions – the Training Admin and one of the Settlement Analysts.
These positions are anticipated to be hired approximately six months after market go-live.
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
By joining the Western EIM, many existing business processes will be impacted and Avista will
adopt an entirely new set of market processes to incorporate in daily operations. The primary
business groups impacted by operating in the market include Power Supply, Transmission System
Operations and Accounting/Finance. The Power Supply group will be responsible for generating
hourly market bids for generation resources, while System Operations will implement a new 24-
hour desk with EIM operators representing Avista’s Balancing Authority Area (BAA) in the market
and the Accounting/Finance group will analyze data and CAISO settlement information. These
three groups will need to communicate closely with each other and the plant operators through
phone calls and the aid of the EIM software applications. The Accounting/Finance business unit
will acquire a new Settlements team to perform market settlements and analysis of Avista’s
financial position in the market. Throughout substation and generation projects, a planning and
timing shift will need to occur to align Avista’s delivery schedules with CAISO’s scheduled
updates. If Avista does not align with CAISO’s update schedules for physical changes in the BAA,
such as new substations or transmission lines, Avista’s physical system will not be represented in
CAISO’s market design, which could result in negative financial impacts for Avista.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
As stated in Section 1.1, Avista monitored EIM expansion and development activity in the West
and as more northwest utilities joined the CAISO EIM, it was inevitable that Avista would also
need to join an in-hour market to reduce market liquidity risk and costs to integrate renewable
resources. Avista delayed a market entry decision until the financial and operational risks were
present. Once the MWTG initiative was deferred in April 2018, Avista decided to pursue entry to
the Western EIM in December 2018 since it was the only market option available.
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer,
spend, and transfers to plant by year.
The EIM Program began in April 2019, and capital project progressively began in May 2019. The
bulk of the capital investments centered on the implementation of the EIM software, the upgrade
of Avista’s metering infrastructure across generation and substation to install revenue quality
meters capable of secure 5-minute reads, and the upgrade of some plant control systems in
generation. While the completion of the generation and substation projects will be progressive
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 281 of 309
Energy Imbalance Market
Business Case Justification Narrative Page 9 of 12
throughout late 2020 and into early 2021, the EIM software applications will not be complete
until market entry in March 2022.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
In April of 2019, Avista announced its own clean energy goals that will transition our resource
mix to 100 percent clean by 2045. Also in 2019, Washington State passed clean energy legislation
that will drive additional renewable resources to be built in Avista’s BAA to meet specific emission
reduction requirements between 2030 and 2045. Any additional renewable resource integrated
in Avista’s service territory results in a reduction of hydro flexibility to follow these variable
resources, and the EIM is the most efficient and cost effective way to provide the required flexible
ramping capability.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed and re-evaluated throughout the project
Avista conducted a cost to benefit analysis based on the information developed from the E3
benefit study and the EIM Program Initiation Charter. Based on the estimated benefits and costs
from these assessments, Avista anticipates breaking even with its EIM investments in 7-8 years
assuming an annual revenue of $6M from market participation.

Avista performed an additional economic analysis based on the updated costs estimates provided
in the EIM Scope Document. Based on the new integration cost of $32.1 million and on-going
costs of $3.9 million, an annual revenue of $7.8 million is needed to break even after 10 years of
market operations. This is still well within the range of estimated benefits determined by E3 and
quite a bit less than CAISO reported benefits for IPC and PGE in 2018 and 2019. If Avista’s actual
EIM system benefits are closer to or exceed the potential upper bound of $12 million, as
determined by E3 and experienced by other similar situated EIM participating utilities, then
Avista customers will see positive revenue in a much shorter time period. The economic analysis
did not consider other EIM benefits such as reduced flexible ramping requirements, reliability
and system visibility enhancements, and reductions in greenhouse gases.

2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
Avista internal stakeholders include: Power Supply, Transmission System Operations, SCADA,
Generation Production & Substation Support, Substation Engineering, Finance & Accounting,
Distribution System Operations, Risk, Network and Technology. Avista’s primary external
stakeholder is CAISO, however the EIM software vendors – Power Costs, Inc., and Power
Settlements – are also key stakeholders. The below table represents business units that will
perform capital projects under the EIM BC and the associated rate jurisdiction:
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 282 of 309
Energy Imbalance Market
Business Case Justification Narrative Page 10 of 12

2.8.2 Identify any related Business Cases
The Energy Imbalance Market Business Case and the Resource Metering, Telemetry and Controls
Upgrade Business Case were initiated in 2017 to prepare Avista to join an organized energy
market. In 2019, the Resource Metering, Telemetry and Controls Upgrade Business case scope,
and the then allocated $2.21M (2019 and 2020 funds), were consolidated under the Energy
Imbalance Market Business Case, which at that time, and had a placeholder estimate of $9.4M.
With the help of Utilicast, Avista continues to gain a better understand of the current status and
capability of existing equipment and full pre-market integration requirements. This information
has been used to create the current Program estimate.
Market entrance is also dependent on the creation and integration of the Full Network Model
delivered under the SCADA/SOO/BuCC BC (System Operations Office and Backup Control Center).

3.1 Steering Committee or Advisory Group Information
The EIM Business Case has the following levels of program governance; the business unit
Advisory Committees, the Director Steering Committee and Executive Steering Committee.
 Advisory Committees – varies by business unit for technical subject matter expertise

 EIM Director Steering Committee – Scott Kinney, Andy Vickers, Mike Magruder, Jim
Corder, Hossein Nikdel, Pat Ehrbar, Todd Colton, Adam Munson and Clay Storey

 EIM Executive Steering Committee – Jason Thackston, Heather Rosentrater, Jim Kensok,
Ryan Krasselt and Kevin Christie
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 283 of 309
Energy Imbalance Market
Business Case Justification Narrative Page 11 of 12
3.2 Provide and discuss the governance processes and people that will provide oversight
The Advisory Committees consist of the subject matter experts in the various business units who
can direct the technical work, make engineering decisions and deliver the technical solution that
meets the business need. The Advisory Committee is supplemented with input and knowledge
from Stakeholders amongst neighboring business units. As needed, members of the Director
Program Steering Committee will participate in the Advisory Committee meetings for input and
decisions. The EIM Program manager will be invited to all Advisory Committee meetings and
serve as a consistent conduit from the Advisory Committees to the EIM Program Steering
Committee. Communication of project schedule risks, scope issues and financial impacts will be
provided by the various project managers at the Advisory Committees and, where appropriate,
reported to the EIM Director or Executive Steering Committee. The Advisory Committee does not
have the authority to approve change requests, but must seek approval from the EIM Director
Steering Committee.
Program level authority sits with the EIM Director Steering Committee, and the Executive
Steering Committee. Ultimate approval authority sits with the Executive Steering Committee. The
Executive Steering Committee is responsible for taking recommendations from the Director
Steering Committee and ultimately making Program level decisions for use of contingency
funding. In the unforeseen event that the EIM Program schedule is at risk, the Executive Steering
Committee has the right to review and adjust the EIM go-live date. Members of the Executive
Steering Committee and the Program Sponsors would be responsible for this re-negotiation of
the EIM Implementation Agreement with the CAISO.
3.3 How will decision-making, prioritization, and change requests be documented and monitored
The EIM Program has implemented procedures and documentation to provide effective
mechanisms to control the scope of the program, manage issues and risks and monitor progress.
Project level change requests will be discussed at the Advisory Committees, and approvals will
be granted at the EIM Director Steering Committee. Program level management of decisions and
documents will be discussed at the EIM Director and Executive Steering Committees and posted
to the EIM SharePoint site. Enterprise Technology projects, and their associated processes, will
be managed within Clarity. Generation, transmission operations and substation projects will be
managed through their established project management processes and procedures, and final
documentation posted to the EIM SharePoint site. Each project artifact will reference the EIM
program with narrative related to EIM scope, CAISO track, requirements, and the financial
structure with the EIM Parent Project ID of EIM422 and the associated Expenditure Request (ER)
and Budget Item (BI). The request to open EIM projects will be reviewed by the EIM Program
Manager and approved by the Business Case Sponsor.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Business Case Justification Narrative Page 12 of 12
The undersigned acknowledge they have reviewed the Energy Imbalance Market Business Case
and agree with the approach it presents. Significant changes to this will be coordinated with and
approved by the undersigned or their designated representatives.

Business Case Owner

Business Case Sponsor

Business Case Sponsor

Steering/Advisory Committee Review

Template Version: 05/28/2020
12-17-2020
12-17-20
12-17-2020
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Energy Markets Modernization & Operational Efficiency
Business Case Justification Narrative Page 1 of 11
EXECUTIVE SUMMARY
Avista participates in two energy markets operated by the California Independent System
Operator (CAISO) – the Market Redesign Technology Upgrade (MRTU) and the Western Energy
Imbalance Market (WEIM). Avista began transacting with the CAISO in June 2017 through
participation in MRTU, which allows entities outside the CAISO balancing authority area to
submit hourly energy bids at specific transmission intertie locations. This day-ahead market
gave Avista access to economically priced solar energy, provides an opportunity to optimize
internal resource flexibility by importing generation into CAISO, and provides access to
additional generation during resource reliability scarcity events. As of Q3 2022, total net benefit
generated from MRTU is approximately $17.1 million, with yearly benefits averaging
approximately $2.9 million.

On March 2, 2022, Avista joined the WEIM. The WEIM is a real-time, intra-hour energy market
that facilitates regional resource dispatch on a five-minute basis to dispatch the lowest cost
resources across the entire market footprint, while balancing in-hour load and resource
obligations. This market allows participants to lower energy costs by either dispatching less
expensive resources to meet load obligations, or by increasing revenue through the bidding of
excess energy into the market. With more than 80% of the western interconnection load
transacting in the WEIM, the liquidity of the hourly bi-lateral market has been significantly
impacted, as market rules require participants to determine resource schedules well in advance
of the operating hour. As renewable generation portfolios are increasingly mandated, market
participation can ease the financial pressure of integrating renewable resources, while
maintaining reliability. According to Avista’s internal benefit calculation, the total net benefit
generated from the WEIM is approximately $6 million as of Q2 2022.

Based on operational improvements and market design changes, the CAISO releases annual
market technology updates in partnership with software vendors. Avista’s participation is
dependent on ensuring the market software suite and associated integrations, are compliant.
Avista estimates these upgrades and enhancements at $500k annually, and must typically be
applied simultaneously across multiple systems, with primary impacts to and approvals from
Power Supply, System Operations, Generation Production & Substation Support (GPSS) and the
WEIM Settlements team. Market compliance obligations and business approvals will determine
when an upgrade is applied. Failure to comply with the upgrades in the given timeframe will
disrupt Avista’s ability to gain access to cost-efficient power in the market, lead to missed benefit
opportunities, and may impact Avista’s ability to reliably operate the electric grid.
VERSION HISTORY
Version Author Description Date Notes
1.0 Kelly Dengel Business Case Template 06/25/2021
2.0 Kelly Dengel BC Narrative Update 05/2022 Add ADSS, market benefits
3.0 Kelly Dengel BC Narrative Update 09/2022 Remove ADSS, add MTRU

DocuSign Envelope ID: A5A1F8EA-8169-4878-A69E-DDCB54F614BF
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GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
This program is required to support the application-related software platforms and integrations
implemented to transact in the CAISO markets.
Application upgrades are essential to remain reliable, current, compatible with CAISO market
software releases, and address security vulnerabilities to ensure ongoing value is achieved by
joining CAISO markets. Failure to comply with the upgrades in the given timeframe will disrupt
Avista’s participation in the market, hinder operational efficiency, and may lead to missed
economic opportunities or system reliability issues.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
The primary investment driver for the Energy Markets Modernization & Operational Efficiency
BC is Performance and Capacity. A secondary investment driver is Asset Condition.
The applications in this BC enable Avista’s people to effectively perform the required market
functions, which impact Avista’s ability to operate in the market, optimize generation resources,
gain access to cost-efficient power and reliably operate the electric grid.
Some benefits to upgrades and enhancements to these systems include:
 Continual market participation and the realization of market benefits
 Continual optimization of Avista’s generation resource portfolio
 Continual grid reliability through market participation
 Continuing as a low-cost energy provider though market participation
 Economically managing renewable resource variability through market participation
Requested Spend Amount $2,730,000
Requested Spend Time Period 5 years
Requesting Organization/Department Energy Delivery
Business Case Owner | Sponsor Kelly Dengel | Mike Magruder
Sponsor Organization/Department Transmission System Operations
Phase Execution
Category Program
Driver Performance & Capacity
DocuSign Envelope ID: A5A1F8EA-8169-4878-A69E-DDCB54F614BF
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1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
The applications in Section 2 are essential to efficient market operations and grid reliability.
Updates/upgrades to these applications, and associated integrations, address operational
changes within the CAISO markets, MTRU and EIM software applications and Avista business
process, all which allow Avista to effectively participate in the market.
Failure to pursue market updates is the primary alternative to keeping these systems market
compliant. This could keep Avista from operating in the market until the upgrade has been
applied, thus keeping Avista from economic market opportunities. For each market release, the
CAISO provides backward compatibility for two previous market release versions, thus giving
Avista some flexibility in determining when an update is applied. The software vendors also
release upgrades independent of CAISO market releases that Avista will need to incorporate into
the delivery cycle.
Performing at least one annual CAISO-initiated software updates as planned supports Avista’s
ability to continue to operate and have access to cost-efficient energy within the market. While
there is flexibility in determining when a minor upgrade can be applied, operational efficiencies
may be lost by omitting recommended upgrades.
1.4 Identify any measures that can be used to determine whether the investment would successfully deliver on the objectives and address the
need listed above.
For the WEIM, the CAISO publishes a quarterly benefit report, which represents a calculation of
each entities’ market benefits. This report will be used in part to reflect Avista’s WEIM benefits
and determine the WEIM Program Implementation BC (2019-2022) investment payback period,
and support justification of on-going upgrades under the Energy Markets Modernization and
Operational Efficiency BC. Avista will also develop an internal benefit report, which will include
considerations for Avista specific operational factors that may not be adequately represented in
CAISO’s benefit calculation. This internal benefit calculation logic will be submitted to the
commissions for review and used in future rate filings to estimate EIM benefits as part of
determining overall power supply expense. These two benefit calculations will help Avista
determine the financial return on the implementation and on-going net benefits. Ensuring all
market related software is updated in accordance with vendor and market timelines enables
Avista to operate efficiently and realize market benefits.
In the fall of 2017, Avista contracted Energy and Environmental Economics (E3) to conduct an
WEIM benefits study, resulting in an estimated benefit range of $2 to $12 million. In Q4 2021,
prior to WEIM entry, Avista agreed to an estimated $5.8 net million in annual system benefits
with Washington Utilities Commission. As of Q2 2022, Avista’s internal net benefit calculation is
estimated at $6 million, while the CAISO Q2 2022 gross benefit calculation was reported at $7.11
million.

As of August 2022, the EIM Program estimates total integration costs at $27.2 million, with $24.1
million in capital and $3.1 million in incremental expense. On-going expense costs are estimated
DocuSign Envelope ID: A5A1F8EA-8169-4878-A69E-DDCB54F614BF
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 288 of 309
Energy Markets Modernization & Operational Efficiency
Business Case Justification Narrative Page 4 of 11
at $3.9 million. With an annual system benefit estimate of $5.8 million, Avista will break even
after approximately 10 years of WEIM market operations. If Avista’s actual WEIM system benefits
are closer to or exceed E3’s estimated upper bound of $12 million, Avista customers will see
positive revenue in a shorter period. Ensuring the WEIM software suite, and associated
integrations, are updated as directed by the software vendors and CAISO will help enable Avista
to achieve these benefits.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
Prior to signing the CAISO WEIM Implementation agreement in April 2019,
Avista hired E3 to conduct an EIM benefit assessment in the fall of 2017. E3
conducted similar benefit assessments for several other utilities to help
understand the potential value of EIM participation. The E3 assessment
estimated that Avista could see a range of annual benefits from $2 to $12 million
from EIM participation. Using Avista’s best estimates for these critical study
assumptions, Avista anticipates EIM annual benefits of $5.8 million, with
potential for benefits to move closer to the upper end of the study range
depending upon observed market price volatility. The E3 EIM is posted here on
the EIM SharePoint site.
1.5.2 For asset replacement, include graphical or narrative representation of metrics associated with the current condition of the asset that is proposed for
replacement.
N/A

Option Capital Cost Start Complete
Support EIM vendor and market enhancements $2.5M 07/2022 07/2027

2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Avista intends to follow the recommended application refresh and expansion requirements for
market applications as outlined by the market software vendors and the CAISO. The requested
allocation is based primarily on maintaining market participation, software system compatibility,
addressing software security vulnerabilities and ensuring ongoing value is achieved from
participation in the EIM and MTRU.

This BC supports upgrades to the market software software, including Power Costs, Inc. (PCI),
SettleCore and Itron, and associated changes to the integration software, including, MuleSoft
and Globalscape. In addition, updates to secondary support applications such as Plant
Information (PI), and integrations with third-party providers for EIM forecasts amongst others.
For the WEIM, the PCI software is a cloud-based Software as a Service (SaaS) solution, while the
SettleCore, Itron MV90 and ADSS applications are on premise. For the MTRU, the PCI software is
on premise. The capital request under this BC includes funds for professional services, labor, and
DocuSign Envelope ID: A5A1F8EA-8169-4878-A69E-DDCB54F614BF
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 289 of 309
Energy Markets Modernization & Operational Efficiency
Business Case Justification Narrative Page 5 of 11
non-labor associated with application upgrades. As the SettleCore and Itron applications are on
premise, it also includes upgrades to server and database hardware. The EIM MV90 installation
is planned for a hardware refresh in 2024, with costs estimated at $100k, while the SettleCore
installation is planned for a hardware refresh in 2026, with costs estimated at $130k. The capital
allocation request in 2024 and 2026 reflects funding these activities.

Apart from Itron’s EIM MV90 agreement and the on-prem installation of PCI software to support
MTRU, professional services to support these upgrades are included in the maintenance
agreements. Upgrades to the SettleCore software will be performed by the vendor, while the
hardware/database maintenance will be supported by Avista. The roadmap for the next five
years includes refreshing and/or expansion initiatives to these core market systems:
 PCI Asset Operations
o Generation Outage Management System (GOMS) – Performs functions
to submit planned and unplanned outages to CAISO for the generation
units.
o Transmission Outage Management System (TOMS) – Performs
functions to submit planned and unplanned outages to CAISO for the
transmission lines.
 PCI GenManager Front Office
o Participating Resource Scheduling Coordinator (PRSC) Bidding &
Scheduling System – Performs Merchant functions to submit bids and
base schedules to CAISO for participating resources.
o EIM Entity Scheduling Coordinator (EESC) Scheduling System – Performs
Entity (Balancing Authority) functions to submit base schedules for both
participating resources and non-participating resources.
 PCI Energy Accounting
o Energy Accounting System – Performs meter verification, estimation and
editing (VEE) for generation and interchange metering to produce and
share Settlement Quality Meter Data (SQMD) with CAISO.
Item Labor Hardware Item Labor Hardware
Comm Server 30,000$ 30,000$ Comm Server 30,000$ 22,000$
App Server 20,000$ App / OS work 32,000$
Database 19,200$ Database 25,600$
Total 69,200$ 30,000$ RabbitMQ 20,000$
Total 107,600$ 22,000$
Grand Total: 99,200$ Grand Total: 129,600$
MV90 - 2024 SettleCore - 2026
DocuSign Envelope ID: A5A1F8EA-8169-4878-A69E-DDCB54F614BF
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 290 of 309
Energy Markets Modernization & Operational Efficiency
Business Case Justification Narrative Page 6 of 11
 SettleCore Power Settlements
o PRSC Settlement System – Performs Merchant settlement functions for
the participating resources and activities.
o EESC Settlement System – Performs Entity settlement functions for non-
participating resources and transmission resources.
 SettleCore Visual Analytics
o Performance & Analytics System – Performs a near real-time market
analytic functions in a visual display.
 Itron EIM MV90
o Head-End Meter System – Collects 5-minute interval generation and
interchange meter data

2.2 Discuss how the requested capital cost amount will be spent in the current year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy
Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]

At minimum, an annual CAISO-market update will be required for market software applications.
Based on the content in the market release, additional integrations may be required. Updates to
third-party wind and solar forecast integration may also be included. The below table represents
the anticipated capital allocation request per year and a summary of what enhancement projects
will be addressed.

BC Year Capital Request Projects/Deliverables Summary
2023 $500,000 Software and integrations upgrades
2024 $600,000 Software, integrations, EIM MV90 hardware upgrades
2025 $500,000 Software and integrations upgrades
2026 $630,000 Software, integrations, SettleCore hardware upgrades
2027 $500,000 Software and integration upgrades
Total $2,730,000

2.3 Outline any business functions and processes that may be impacted (and how) by the business case for it to be successfully implemented.
By joining the WEIM, many existing business processes were impacted and Avista adopted an
entirely new set of market processes to incorporate in daily operations. The primary business
DocuSign Envelope ID: A5A1F8EA-8169-4878-A69E-DDCB54F614BF
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 291 of 309
Energy Markets Modernization & Operational Efficiency
Business Case Justification Narrative Page 7 of 11
groups impacted by operating in the market include Power Supply, System Operations, Thermal
Operations, Hydro Operations and EIM Settlements. The Power Supply group is responsible for
generating hourly base schedules and market bids for generation resources, while System
Operations implemented a new 24-hour desk with EIM operators responsible for balancing load
and dispatching generation resources. The Thermal Operations and Hydro Operations groups
are responsible for submitting both planned and unplanned outage data associated with
generation resources. The WEIM Settlements group will analyze data and CAISO settlement
information. These groups need to communicate closely with each other and plant operators
through phone calls and the aid of the software applications. In addition, the Enterprise
Technology operations team will need to support the WEIM software suite 24x7 and the
delivery teams will need to support on-going upgrades to the system. Failure to comply with
the given upgrades within the specified time frame, will likely disrupt Avista’s participation in
the market and hinder operational efficiency.

2.4 Discuss the alternatives that were considered and any tangible risks and mitigation strategies for each alternative.
During the WEIM Program implementation, Avista leadership discussed the merits of purchasing
market software, purchasing software from a single EIM vendor, developing in-house EIM
software, enhancing existing in-house software and how to integrate these systems with CAISO
systems. Ultimately, Avista chose to purchase market software from two WEIM vendors to
leverage native integrations amongst the software suite and allow those systems to interface
with CAISO applications directly. Where necessary, Avista developed internal integrations with
existing Avista software (ADSS, EIM MV90, PI, and Oracle Financials) and third-party variable
energy resource forecast providers. Avista leadership determined this model was most ideal in
limiting complexity and on-going maintenance costs. Therefore, use of the WEIM software suite
to maintain efficient market operations is most ideal. However, if a portion of the software suite
was unavailable, and the degree to which it would be unavailable, Avista personnel could
manually submit some data through the CAISO web-based applications to continue market
participation. This practice is not sustainable and doesn’t allow for efficient operations or
optimization. In addition, if the software were completely unavailable, due to a software outage,
network outage or non-compliant software, Avista would be unable to participate in the market
until the issue were resolved. In either event, hindering Avista’s participation in the market will
limit Avista’s access to competitively-price power and limit Avista’s ability to achieve the
anticipated market benefits.
For each market release, the CAISO provides backward compatibility for two previous market
release versions, thus giving Avista some flexibility in determining when an update is applied. In
addition, the software vendors also release upgrades independent of CAISO market releases that
Avista will need to incorporate into the delivery cycle. The software users will determine what
updates are most critical and consider bundling updates to minimize the number of upgrades
performed annually. While there is flexibility in determining when an upgrade can be applied,
additional functionality and efficiencies may be lost by omitting recommended/required
upgrades.
DocuSign Envelope ID: A5A1F8EA-8169-4878-A69E-DDCB54F614BF
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 292 of 309
Energy Markets Modernization & Operational Efficiency
Business Case Justification Narrative Page 8 of 11
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer, spend, and transfers to plant by year.
This is a BC with discrete projects that will operate annually, with Transfer to Plant (TTP) within
that same year. There are times that a project may start in Q3/Q4 of one year and TTP the
following year. Typically, application projects will TTP about 60 days prior to the project
completion date (based on the post implementation warranty period and the capture of trailing
charges).
2.6 Discuss how the proposed investment aligns with strategic vision, goals, objectives and mission statement of the organization.
In 2019, Washington State passed clean energy legislation that will drive additional renewable
resources to be built in Avista’s BAA to meet specific emission reduction requirements between
2030 and 2045. In April of 2019, Avista announced its own clean energy goals that will transition
the generation resource mix to 100 percent clean by 2045. Any additional renewable resources
integrated in Avista’s service territory will result in a reduction of hydro flexibility to follow these
variable resources, and the WEIM is the most efficient and cost-effective way to provide the
required flexible ramping capability.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
Avista’s market software systems are a necessity, as they provide essential functions to Avista.
These systems require upgrades and enhancements to maintain compatibility, reliability, address
security vulnerabilities and ensure ongoing value is achieved from market participation. In
addition, the updates must be applied and tested simultaneously across the platform and within
the given upgrade timeframe to maintain market operations. It’s anticipated this funding level
will provide support to complete the annual upgrade requirement, thus mitigating the risk of
market exclusion or suboptimal software performance. It also mitigates the risk of unsupported
applications, security liabilities, and significantly higher upgrade costs because of the upgrade
deferment.
The CAISO publishes quarterly WEIM benefit statements for each entity, while Avista personal
calculate WEIM and MTRU benefits. The WEIM Settlements team will shadow the CAISO
calculations to validate the CAISO-generated Avista benefit totals. In addition, Avista will perform
an internal calculation of Avista’s benefits. Although Avista has an estimated annual system
benefit of $5.8 million (Section 1.4), Avista will update their investment cost analysis based on
actual annual benefit results. On-going investment in the market software suite is prudent, as it
allows Avista to efficiently operate in the market, thus enabling Avista to achieve optimal market
benefits.
2.8 Supplemental Information

DocuSign Envelope ID: A5A1F8EA-8169-4878-A69E-DDCB54F614BF
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 293 of 309
Energy Markets Modernization & Operational Efficiency
Business Case Justification Narrative Page 9 of 11
2.8.1 Identify customers and stakeholders that interface with the business case
Delivery within the Energy Markets Modernization & Operational Efficiency BC requires a
partnership between Enterprise Technology (ET) and various business unit teams, including
Power Supply, System Operations, SCADA, GPSS, and the EIM Settlements team under Finance &
Accounting. The Steering Committee members include BC Sponsors and Directors within ET,
Power Supply, System Operations, GPSS, and Finance & Accounting.
The BC Owner works with members of the business and ET, including the ET Delivery Manager,
ET Project Management Office (PMO), the Program Manager and subsequent Project Managers.
The BC Owner is accountable and responsible for all BC related activities and assignments, and
consults members of ET and the business to ensure a strong partnership and navigate project,
funding and priority intricacies throughout the course of the budget year.
Avista internal stakeholders include: Power Supply, Transmission System Operations, SCADA,
GPSS, Finance & Accounting, Distribution System Operations (PI), Risk, Network and Technology.
Avista’s primary external stakeholder is CAISO, however the EIM software vendors – PCI, Power
Settlements and Itron – are also stakeholders.

2.8.2 Identify any related Business Cases
The Energy Markets Modernization & Operational Efficiency Business Case is related to the WEIM
Program Implementation BC (2019-2022) that implemented the required WEIM software and
metering/controls infrastructure. The MTRU software was implemented under the Energy
Resources Modernization and Operational Efficiency BC.

3.1 Steering Committee or Advisory Group Information
The Energy Markets Modernization & Operational Efficiency Steering Committee members
include BC Sponsors and Owners, and directors within Power Supply, System Operations, GPSS,
Finance & Accounting and Enterprise Technology.
3.2 Provide and discuss the governance processes and people that will provide oversight
Delivery within the Energy Markets Modernization & Operational Efficiency BC requires a
partnership between various business unit teams and Enterprise Technology (ET). This BC will
be governed by the Technology Planning Group (TPG), the Integrated Oversight Committee
(IOC), and Program/Project Steering Committees.
The Capital Planning Group (CPG), an independent body, establishes funding allocations for
each BC across the enterprise. The TPG sets priority across the technology investment portfolio,
balancing: strategic alignment, business value, and customer benefits, as driven by the strategic
initiatives established by Avista leadership. The IOC evaluates and compares all of the
application portfolio project priorities on a weekly basis, utilizing risk, capacity, and other
situational factors to ensure each planned project is meeting critical milestones.
DocuSign Envelope ID: A5A1F8EA-8169-4878-A69E-DDCB54F614BF
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 294 of 309
Energy Markets Modernization & Operational Efficiency
Business Case Justification Narrative Page 10 of 11
The BC is largely limited by the funding allocation and resource capacity (staff) to meet its goals.
The funding is approved at the BC level by the CPG. The resource capacity constraint is
generally managed by the TPG and the BC owner. Once the two constrains are established, the
BC owner works with steering committee(s) to set project priority and sequencing over a five-
year planning period and is subject to additional funding changes as directed by the CPG.
3.3 How will decision-making, prioritization, and change requests be documented and monitored
As a software application project, prioritization is evaluated by the ET management team on a
weekly basis through the IOC. Each program and project steering committee meets regularly and
oversees scope, schedule and budget within their respective programs and projects and inform
the BC owner of any changes needing escalation to the TPG or CPG for decision-making around
resource or funding constraints.
Any changes in funding or scope are documented at the BC level, via Change Request document
that is presented to the monthly CPG meeting and evaluated for approval.
Changes in scope, schedule, or budget are also documented through a ‘Change Request’ at the
project level and reviewed and approved through a formal workflow process. All projects in this
BC are managed through the PMO, which follows the Project Management Institute (PMI)
standards. Projects initiate with a ‘Charter’ to begin the planning process. When planning is
complete, a ‘Project Management Plan (PMP)’ is created and approved as the projects baseline
for scope, schedule and budget. At the end of execution, an ‘Approval to Go Live’ is submitted
and approved prior to implementation (Transfer to Plant). After the technology is in service and
out of the warranty period, the Project Manager will hold a Lessons Learned, and subsequently
submit an ‘Approval to Close’ prior to finishing the project. All Monitor and Control
documentation and Change Requests are documented and stored to ensure a comprehensive
audit trail.The undersigned acknowledge they have reviewed the EIM Modernization &
Operational Efficiency Business Case and agree with the approach it presents. Significant changes
to this will be coordinated with and approved by the undersigned or their designated
representatives.

Signature: Date:
Print Name: Kelly Dengel
Title: EIM Program Manager
Role: Business Case Owner

Signature: Date:
Print Name: Mike Magruder
Title: Director of Trans System Ops & Planning
Role: Business Co-Case Sponsor
DocuSign Envelope ID: A5A1F8EA-8169-4878-A69E-DDCB54F614BF
Sep-06-2022 | 2:03 PM PDT
Sep-07-2022 | 1:51 PM PDT
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Energy Markets Modernization & Operational Efficiency
Business Case Justification Narrative Page 11 of 11

Signature: Date:
Print Name: Scott Kinney
Title: Director of Energy Resources
Role: Business Co-Case Sponsor

Signature: Date:
Print Name: Scott Kinney, Mike Magruder, Alexis
Alexander, John Wilcox, Hossein Nikdel

Title: Dir of Energy Supply; Dir of System
Operations; Dir of Gen Prod Sub Support; Dir
of Accounting; Dir of App & Sys Planning

Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
DocuSign Envelope ID: A5A1F8EA-8169-4878-A69E-DDCB54F614BF
Sep-07-2022 | 4:36 PM PDT
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 296 of 309
Generation Plant Annunciation System<Project Name>
Business Case Justification Narrative Template Version: 04.21.2022 Page 1 of 6
EXECUTIVE SUMMARY

The purpose of this business case is to implement a standard annunciation system at all
generation facilities. Avista’s generation facilities do not currently have a standard plant
evacuation and warning system. Each facility has different combinations of audible and visual alerts to inform plant personnel of actions to be taken during emergency situations such as evacuation. Operators, construction and maintenance crews, engineers, and others regularly
work at multiple generation facilities and must be familiar to each plants’ system. Although customized training has been developed for each facility, the differences across the fleet could result in confusion during an emergency and jeopardize the safety of personnel.

Standardization of annunciation was identified as a necessary safety improvement by the Safety
Action Board. As a result of the requested action, Generation Controls Engineer worked closely
with plant operations and maintenance/construction crews to develop a standard solution to
implement at Avista’s generation facilities. The system will provide standard audible alerts to all
on-stie personnel for multiple condition including plant evacuation, generator start warning, alarm
condition with prioritization, and other customizable alerts as required. The cost and installation of the system is estimated to be $50,000 per site. The installation will be completed over 3 years
with a total cost of $450,000. The implementation of the system will significantly improve overall
safety at the plant by familiarizing personnel with common audible alerts and improve everyone's response to a potentially hazardous situation. The recommended solution was reviewed by
GPSS Engineering and approved by GPSS Management.

VERSION HISTORY
Version Author Description Date Notes
1.0 Jeremy Winkle Original submission 7/7/2021 Full Approval
2.0 Kristina Newhouse Updated and moved to 2022 template 8/15/2022

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Generation Plant Annunciation System<Project Name>
Business Case Justification Narrative Template Version: 04.21.2022 Page 2 of 6
GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
Each facility has different combinations of audible and visual alerts to inform plant personnel of actions to be taken during emergency situations such as evaluation.
Operators, construction and maintenance crews, engineers, and others regularly work at multiple generation facilities and must be familiar to each plants system. Although customized training has been developed for each facility, the differences across the
fleet can result in confusion during an emergency situation and jeopardize the safety of personnel.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
The main driver of this business case is safety. Standardization of annunciation has identified as a necessary safely improvement by the Safety Action Board.
1.3 Identify why this work is needed now and what risks there are if not approved or is deferred
This work should be completed now to protect plant personnel and maintain Avista’s
high safety standards. This project will improve and standardize the alert and alarming
system at each site leading to better response during emergency situations.
If this work in not approved or deferred, the plant will continue to operate with different
alarms and lights to represent emergency and warning situations. The differences between plants may create confusion for personnel working at multiple sites and negatively impact response during an emergency potentially leading to severe injury or
death.
1.4 Identify any measures that can be used to determine whether the investment would successfully deliver on the objectives and address the need listed above.
The investment in a standard annunciation system will be measured by the following:
• Complete of a Safety Action Board item for a standard for common plant alarms
across generation facilities
Requested Spend Amount $450,000
Requested Spend Time Period 3 years
Requesting Organization/Department GPSS
Business Case Owner | Sponsor Kristina Newhouse | Alexis Alexander
Sponsor Organization/Department GPSS
Phase Initiation
Category Program
Driver Performance & Capacity
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 298 of 309
Generation Plant Annunciation System<Project Name>
Business Case Justification Narrative Template Version: 04.21.2022 Page 3 of 6
• Standard annunciation training for all plants available on the Avista Learning Network
• Excellent safety records at generation facilities
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
Safety Action Board – Standard for Common Plant Alarm
2. PROPOSAL AND RECOMMENDED SOLUTION
The recommended solution is installing a standard annunciation system at Avista’s
generation facilities. Generation Controls Engineer worked closely with plant operations
and maintenance/construction crews to develop a standard solution to implement at Avista’s
generation facilities. The system will provide standard audible alerts to all on-stie personnel
for multiple conditions including plant evacuation, generator start warning, alarm condition with prioritization, and other customizable alerts as required. The cost and installation of
the system is estimated to be $50,000 per site.

Option Capital Cost Start Complete
Install Standard Annunciation Systems at all
General Facilities
$450,000 01 2023 12 2025
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Safety of personnel working in and around generation facilities was the reason for this capital request. The recommended solution was developed after multiple meetings
with operations, and maintenance/construction personnel that work regularly in generation facilities to develop a standard annunciation system. These meetings resulted in developing a standard annunciation system to be installed at each
generation facility with common audible and visual alerts and the ability to include additional customize alarms as required. A prototype system was constructed and testing for each operations group. Each operations group agreed on the created
standard and installation at their facilities.
2.2 Discuss how the requested capital cost amount will be spent in the current year
(or future years if a multi-year or ongoing initiative). (i.e. what are the expected functions,
processes or deliverables that will result from the capital spend?). Include any known or estimated reductions to O&M as a result of this investment.
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy
Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]
The standard annunciation systems will need to be installed at nine facilities over three years starting in 2023. There will be three installations per year based on an estimated
cost of $150,000 annually. The capital cost will include approximately $15,000 in
equipment per site and $35,000 for design and installation labor.
The standardization of annunciation systems across the generation fleet will ultimately
reduce O&M costs as the labor required to develop and conducting training for individual sites will no longer be required. The training will be standard for all generation facilities resulting in a reduction in O&M labor costs.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 299 of 309
Generation Plant Annunciation System<Project Name>
Business Case Justification Narrative Template Version: 04.21.2022 Page 4 of 6
2.3 Outline any business functions and processes that may be impacted (and how) by the business case for it to be successfully implemented.
All personnel working in and around generation facilities will be impacted to
successfully implement this business case. Personnel will need to become familiar with new standards and understand the expected actions. This will require changes to
training processes and requirements lead by plant operations.
The design and installation of the systems will require support from Generation Controls/Electrical Engineering, Network Engineering, Electric shop and PCM shop.
No outages will be required to complete this work and the day-to-day operations at the generation facilities will not be significantly impacted.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
During the development of the generation annunciation standard, multiple designs and equipment were consider. Ultimately, the chosen design standard was the most cost
effective and minimized risk. The core of the design will be standard at each facility, but the design can also be easily adapted to meet the need of each facility depending on facility size/layout and operational functions.
2.5 Include a timeline of when this work will be started and completed. Describe when the investments become used and useful to the customer.
Three installations per year over a three-year period, will be completed. The
investments for each facility will become used and useful after installation. The following is an example timeline:
Year 1
• Monroe Street HED
• Upper Falls HED
• Post Falls HED
Year 2
• Long Lake HED
• Little Falls HED
• Nine Mile HED
Year 3
• Noxon Rapids HED
• Boulder Park
• Rathdurm CT
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
The addition of standard annunciation systems at each generation facility increases safety at each site. These projects reduce the risk of severe injury or death during an
emergency and directly aligns with Avista’s safety goals.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Generation Plant Annunciation System<Project Name>
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2.7 Include why the requested amount above is considered a prudent investment, providing or attaching any supporting documentation. In addition, please explain
how the investment prudency will be reviewed and re-evaluated throughout the
project
There is currently no annunciation standard for audible and visual alerts withing Avista’s
generating facilities. These annunciation systems are critical as they inform plant
personnel of actions to be taken during emergency situations such as evacuation. Operators, construction and maintenance crews, engineers, and others regularly work
at multiple generation facilities and must be familiar with the various annunciation system at each facility. Standardization of annunciation was identified as a necessary safety improvement by the Safety Action Board. A new system will provide standard
audible alerts to all on-stie personnel for multiple condition including plant evacuation,
generator start warning, alarm condition with prioritization, and other customizable alerts as required.
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
The following stakeholders will interface with this business case:
• Controls Engineering • Electrical Engineering
• Protection Engineering • Generation Operations
• Project Management • PCM Shop
• Electric Shop

2.8.2 Identify any related Business Cases
None
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
Each project with have a project manager and steering committee for ongoing vetting.
Since projects will be on smaller scale the steering committee for each project will consist of the Controls/Electrical Engineering Manager, the Protection Control Meter
Technician Foreman, and either the Spokane River Plant Operations Manager, Cabinet Gorge Plant Operations Manager, Noxon Rapids Plant Operations Manager, Lower Spokane River Plant Operations Manager, or Thermal Operations Plant Manager.
3.2 Provide and discuss the governance processes and people that will provide oversight
More detailed project governance protocols will be established during the project
chartering process. The Steering Committee will allocate appropriate resources to all project activities once the scope is better defined.
3.3 How will decision-making, prioritization, and change requests be documented and monitored
Project decisions will be coordinated by the project manager. The Steering Committee
will be advised when necessary. Regular updates will be provided to the Steering Committee by the project manager as project scope, schedule and budget are defined, and through the course of the project execution.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 301 of 309
Generation Plant Annunciation System<Project Name>
Business Case Justification Narrative Template Version: 04.21.2022 Page 6 of 6
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Generation Plant Annunciation
System Business Case and agree with the approach it presents. Significant changes to this will be coordinated with and approved by the undersigned or their designated
representatives.

Signature: Date: 8/15/2022
Print Name: Kristina Newhouse
Title: Controls & Electrical Eng Manager
Role: Business Case Owner

Signature: Date:
Print Name:
Title:
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Automation Replacement
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EXECUTIVE SUMMARY

The purpose of this program is to replace aging controllers and governors. Controllers are used to automate, control and monitor Avista’s generating facilities. The controllers of concern
are aging and introducing an increase in hardware, software, and communication failures that
limit Avista’s ability to operate generating facilities reliably. The recommended solution is to replace all aging controllers and governors proactively on a schedule that takes into account
resources and outage availability. The project cost to replace an outdated controller costs about $300,000-$500,000 depending on the complexity. Proactively replacing these devices benefits customers by reducing unexpected plant outages that require emergency repair with
like equipment. A planned approach allows engineers and technicians to update logic programs more effectively and replace hardware with current standards.
When this program was proposed in 2017, a multi-year plan was provided that captured the
various controllers through Avista’s generating facilities that need to be upgraded. The
program allows the overdue replacements of controllers to happen at quicker pace to improve reliability and also support the HMI program. Repalceing aging governors is being added to
scope in 2022 as many governor controls will be replaced with PLC based governors. The risk of not continuing this business case slows progress toward replacing aging and outdated controllers and governors that could results in an unplanned outage or a cyber security issue.
The recommended solution was reviewed by GPSS Engineering and approved by GPSS
Management.

VERSION HISTORY
Version Author Description Date Notes
1.0 Kristina Newhouse Initial version 6/21/2016
2.0 Kristina Newhouse
Added meters to scope, changed driver
to “Asset Condition,” and clarified
advisory group info
6/28/2019
3.0 Kristina Newhouse Updated to 2020 template 7/31/2020
4.0 Kristina Newhouse
& Jeremy Winkle
Updated to 2022 template, updated
schedule, and updated spope to include
governors and removed meters
8/25/2022

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
The purpose of this program is to replace aging Distributed Control Systems (DCS), Programmable Logic Controllers (PLC). DCSs and PLCs, referred to as controllers,
are used throughout Avista’s generating facilities to control and monitor Avista’s generating units and auxiliary systems. Controllers collect meter data that is used in
logic programs. Controllers used in generating facilities to automate, control, and
monitor are aging and introducing an increase in hardware, software, and
communication failures that limit Avista’s ability to operate generating facilities
reliably. The aging hardware of concern requires computer drivers that do not fit in
new computers therefore we are required to operate computers with legacy operating systems. This creates a Cyber Security risk.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
The major driver of this business case is Asset Condition. Outdated controllers have modules that are over 20 years old and spare parts are limited. Additional laptops must
be maintained to configure Bailey and Modicon. Vulnerability scanning is not performed
on outdated control systems. Incorporating aging controllers into modern designs is limited and often not possible. Improving the asset condition in this case will improve
reliability within the generating facilities.
1.3 Identify why this work is needed now and what risks there are if not approved or is deferred
Replacing controllers with new standards will reduce cyber security risk and unexpected plant outages that require emergency repair with like equipment. Planned projects to replace aging controllers and governors before they fail will allow for more
efficient upgrades with standardized hardware and software that engineers, and technicians are trained on.
Requested Spend Amount $500,000
Requested Spend Time Period 15 years
Requesting Organization/Department GPSS
Business Case Owner | Sponsor Kristina Newhouse | Alexis Alexander
Sponsor Organization/Department GPSS
Phase Execution
Category Program
Driver Asset Condition
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1.4 Identify any measures that can be used to determine whether the investment would successfully deliver on the objectives and address the need listed above.
Replacing hardware before it fails and software before it introduces a security risk
while moving toward our standardized controllers and governors will be a success.
In the past we’ve planned on upgrading controllers and governors during unit
overhauls but this pace is slow when equipment is 20 years old and spare parts are
not readily available. The intent of this business case is to increase the number of controllers being replaced today which is about 1-3 controllers a year.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for replacement.
2. PROPOSAL AND RECOMMENDED SOLUTION
The recommended solution is to upgrade all controllers and governors. It includes replacing all aging controllers proactively on a schedule that takes into account resources,
outage availability, and EIM schedule demands. This option addresses aging hardware
and software concerns as well as the cyber security vulnerabilities.

Option Capital Cost Start Complete
[Recommended Solution] Upgrade Controllers and
Governors
$6.5M 01 2018 12 2033
[Alternative #1] Software Upgrade for Controllers $2.5M 01 2018 12 2025
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Information that was considered for this capital request included information from various individuals throughout the company. Technicians shared their challenges
maintaining aging controllers and utilizing used spare parts that are often not reliable. It included feedback from operators that have concerns with keeping their plants
running using 20 year-old controllers they depend on. Engineers expressed the
design limitations they face when asked to install modern systems that tie into outdated technology. IT Security Engineers shared their concerns with technician
requiring computers that operate Windows 95 and XP to access the controllers using
the software required.
2.2 Discuss how the requested capital cost amount will be spent in the current year
(or future years if a multi-year or ongoing initiative). (i.e. what are the expected functions,
processes or deliverables that will result from the capital spend?). Include any known or estimated reductions to O&M as a result of this investment.
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy
Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]
The requested capital cost for this program takes into consideration that project costs vary depending on the complexity of the controller and meter. Limited resources for
design and construction as well as available outages make it necessary for upgrades
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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to be spread out over many years. Upgrading controller will reduce forced outages due to failures and unplanned O&M expenses.
Controllers that need to be replaced that are not part of a larger project include:
• Boulder Park Balance of Plant 2022 Design / 2023 Construction
• Upper Falls Headgate 2023 Design / 2024 Construction
• Control Works Spillway 2024 Design / 2025 Construction
• Nine Mile Spillway 2025 Design / 2026 Constuction
• Upper Falls Unit Controls and Governor TBD
• Noxon Units 1, 2, 3, 4, and 5 Governors TBD
• Post Falls South Channel Spillway TBD

Governors that need to be replaced that are not part of a larger project include:
• Noxon Unit 1 2028 Design / 2029 Construction
• Noxon Unit 2 2029 Design / 2030 Construction
• Noxon Unit 3 2030 Design / 2031 Construction
• Noxon Unit 4 2031 Design / 2032 Construction
• Noxon Unit 5 2032 Design / 2033 Construction
2.3 Outline any business functions and processes that may be impacted (and how) by the business case for it to be successfully implemented.
Additional resources are required in order to maintain a schedule and consistently meet
the objectives. Engineering will require a designer to develop new logic programs and designs for installations. The Protection Control Meter Shop will need a resource to
install and commission the PLC programs. The capital cost takes into account
resources needed to perform designs and installations. It also takes into consideration feasibility of plant outages as projects are spread out over time.
This project will benefit Power Supply and System Operations as they are responsible
for dispatching power from Cabinet Gorge plant to meet contractual obligations and managing the day-to-day transmission system operational requirements. It will also
benefit engineering and the shops as they are responsible for providing maintenance and support with the generating facilities.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Alternative 1 is to upgrade software on the controllers. This would include replacing
each system’s software that runs on Windows 95 and Windows XP with a separate
software for each platform that runs on Windows 10. This will mitigate the software and cyber security issue but not the aging hardware issue. Outages would be required, and
the new logic programs would need to be rewritten and fully commissioned. Upgrading
the Bailey software and the Modicon software do not align with our standard PLC platform that our engineers and technicians are trained on. This would introduce two
new software applications. Efficiency to troubleshoot and resolve issues in a timely manner could be impacted.
The do nothing alternative would be to maintain existing controllers as we currently
do today. This includes replacing controller modules as they fail with old spare parts
or refurbish third party parts. Maintaining spare parts allows us to continue using existing infrastructure and logic programs but it does not resolve the long-term issue
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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which is aging equipment that will eventually no longer be available. The risk of outages at undesirable times to replace failed parts becomes more likely the longer
the aging hardware is in service. This alternative also does not resolve the issue with
computers that have unsupported operating systems and are considered a cyber security risk.
2.5 Include a timeline of when this work will be started and completed. Describe when the investments become used and useful to the customer.
This work began in 2018. This business case has funded the replacement of six (6)
outdates controllers over the last four (4) years. Thesesix controllers are in addition to 11 other controllers that have been replaced as part of other large capital projects. Most designs take place one year with installation and transfer to plant the following year
upon competition of the project.
2.6 Discuss how the proposed investment aligns with strategic vision, goals, objectives and mission statement of the organization.
By proactively replacing aging controllers and governors we are able to increase reliability within our generating facilities. This program safely, responsibly, and
affordably improves our customers’ lives through innovative energy solutions.
2.7 Include why the requested amount above is considered a prudent investment, providing or attaching any supporting documentation. In addition, please explain
how the investment prudency will be reviewed and re-evaluated throughout the project
The controllers and governors are both single point failures. If these devices fail they
will cause either a single unit outage or a wider plant outage. If spare parts, from the limited supply on hand, can be found then the outage can be minimized but operating generating facility on outdated equipment requiring computers with unsupported
operating systems is not sustainable, responsible, or cost effective, and exposes the generating facilities to unnecessary risk.
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
• Controls Engineering
• SCADA Engineering
• Mechanical Engineering
• Project Management
• Network Engineering
• Network Operations
• PCM Shop
• Electric Shop
• Mechanic Shop
• Telecom Shop
• Hydro Operations
• Thermal Operations
2.8.2 Identify any related Business Cases
This business case is related to the HMI Control Software business case. As new control software and computers with Windows 10 are planned to be
installed over the next couple years they need to communicate to controllers. The oldest of the aging controllers require computer drivers that do not fit in
new computers.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
Each project with have a project manager and steering committee for ongoing vetting. The steering committee for each project will consist of the Controls Engineering Manager, the
Protection Control Meter Technician Foreman, the SCADA Engineering Manager, and either the Spokane River Plant Operations Manager, Cabinet Gorge Plant Operations Manager, Noxon Rapids Plant Operations Manager, Lower Spokane River Plant Operations
Manager, or Thermal Operations Plant Manager.
3.2 Provide and discuss the governance processes and people that will provide
oversight
More detailed project governance protocols will be established during the project chartering process. The Steering Committee will allocate appropriate resources to
all project activities, once the scope is better defined.
3.3 How will decision-making, prioritization, and change requests be documented and monitored
Project decisions will be coordinated by the project manager. The Steering Committee will be advised when necessary. Regular updates will be provided to the Steering Committee by the project manager as project scope, schedule and
budget are defined, and through the course of the project execution.
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Automation Replacement business case and agree with the approach it presents. Significant changes to this will be coordinated
with and approved by the undersigned or their designated representatives.

Signature: Date: 8/25/2022
Print Name: Kristina Newhouse
Title: Controls/Electrical Engineering Mgr
Role: Business Case Owner

Signature: Date:
Print Name: Alexis Alexander
Title:
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Automation Replacement
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Role: Steering/Advisory Committee Review

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 4, Page 309 of 309
CONFIDENTIAL subject to Attorney’s Certificate of Confidentiality
Entire Document is CONFIDENTIAL
2020 Renewable RFP Summary Report
Pages 1 through 74
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01
S.Kinney, Avista
Schedule 5(R), Page 1 of 1
CONFIDENTIAL subject to Attorney’s Certificate of Confidentiality
Entire Document is CONFIDENTIAL
Contract for Sale of Output from The Rocky Reach Project and
Rock Island Project
Pages 1 through 75
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01
S.Kinney, Avista
Schedule 6(R), Page 1 of 1
July 2021
Northwest Power Pool
NWPP
Resource
Adequacy
Program –
Detailed Design
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 1 of 254
ACKNOWLEDGEMENTS
This document is the culmination of 13 months of effort by the NWPP Resource Adequacy
Steering Committee, with support from Southwest Power Pool, Sapere Consulting, Public
Generating Pool, Munro Advisors, Wright & Talisman P.C., and McDowell Rackner Gibson P.C.
The Steering Committee consists of representatives from:
•Avista
•Balancing Areas on Northern California
•Bonneville Power Administration
•Calpine
•Chelan County PUD
•Douglas County PUD
•Eugene Water and Electric Board
•Grant County PUD
•Idaho Power
•NorthWestern
•NV Energy
•Northwest Power Pool
•PacifiCorp
•Portland General Electric
•Powerex
•Public Service of Colorado
•Puget Sound Energy
•Seattle City Light
•Snohomish County PUD
•Tacoma Power
•Turlock Irrigation District
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 2 of 254
TABLE OF CONTENTS
Acronyms ..................................................................................................................................................................... 4
Executive Summary .................................................................................................................................................. 7
Governance ..................................................................................................................................... 17
Forward Showing Design ........................................................................................................... 46
Section 2: Appendix A - Annual Assessments ............................................................................................. 93
Section 2: Appendix B - Modeling Adequacy Standard and PRM ....................................................... 98
Section 2: Appendix C - PRM Allocation Methodologies ..................................................................... 105
Section 2: Appendix D - Qualified Capacity Contribution Modeling ................................................ 108
Section 2: Appendix E - Transmission Modeling Considerations ...................................................... 127
Section 2: Appendix F - Portfolio Construction Details and Examples ............................................ 130
Section 2: Appendix G – Indicative annual assessment results ........................................................... 134
Operational Design .................................................................................................................... 140
Section 3. Operational Design: Table of Contents ................................................................................... 141
Section 3: Appendix A – Processes & Procedures ................................................................................... 194
Appendix - 2B Stakeholder Advisory Committee Engagement and Feedback............................. 196
Glossary ................................................................................................................................................................... 246

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 3 of 254
ACRONYMS
BA Balancing Authority
BAA Balancing Authority Area
BOD Board of Directors
CAISO California Independent System Operator
CCH Capacity Critical Hours
CEO Chief Executive Officer
CONE Cost of New Entry
COS Committee of States
CP Coincident Peak
CR Contingency Reserves
DR Demand Response
EDAM Extended Day-Ahead Market
EEA Energy Emergency Alerts
EFDHcch Equivalent Forced Derating Hours Occurring on CCH
EFOF Equivalent Forced Outage Factor
EFOR Equivalent Forced Outage Rates
EFORd Equivalent Demand Forced Outage Rate
EIM Western Energy Imbalance Market
ELCC Effective Load-Carrying Capability
ESR Energy Storage Resource
FERC Federal Energy Regulatory Commission
FOHcch Forced Outage Hours Occurring on CCH
FS Forward Showing
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 4 of 254
GADS Generator Availability Data System
HE Hour Ending
ICAP Installed Capacity
IRP Integrated Resource Plan
LFU Load Forecast Uncertainty
LOLE Loss of Load Expectation
LRE Load Responsible Entity
LRZ Load and Resource Zone
LSE Load Serving Entity
MW Megawatt
MWh Megawatt Hour
NC Nominating Committee
NCP Non-Coincident Peak
NERC North America Electric Reliability Corporation
NWPP Northwest Power Pool
OATT Open Access Transmission Tariff
OD Operating Day
P50 1-in-2 Peak Load Seasonal Values
PD Program Developer
PO Program Operator
PRM Planning Reserve Margin
PS Preschedule
QCC Qualified Capacity Contribution
RA Resource Adequacy
RAPC Resource Adequacy Participant Committee
SAC Stakeholder Advisory Committee
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 5 of 254
SC Steering Committee
SPP Southwest Power Pool
TDF Transmission Distribution Factors
TSP Transmission-Service Provider
UCAP Unforced Capacity
VER Variable Energy Resource
WECC Western Electricity Coordinating Council
WIEB Western Interstate Energy Board
WRAA Western Resource Adequacy Agreement
WSPP Western System Power Pool

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 6 of 254

NWPP Resource Adequacy
Program Detailed Design

Executive Summary

JUNE 2021

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 7 of 254
ES1. Background
The integrated regional power system is in transition. The impending retirement of several
thermal generators within and outside the region (the Western US and Canada) mixed with
increasing variable energy resources (VERs), has led to questions about whether the region
will continue to have an adequate supply of electricity during critical hours. In the past four
years, several studies have identified an urgent and immediate challenge to the regional
electricity system’s ability to provide reliable electric service during high demand conditions.
These developments threaten to upset the balance of loads and resources within the region
and, if not properly addressed, will increase the risk of supply disruptions during Winter and
Summer, increase financial risk for utility customers, and hinder the ability of the system to
meet environmental goals and legal requirements.
Beginning in early 2019, the Northwest Power Pool (NWPP) has coordinated a broad coalition
to explore the nature of the challenge and investigate mechanisms to assure a high likelihood
of adequate supply to meet customer demand under a wide array of scenarios. These include
a Forward Showing (FS) planning mechanism and an Operational Program (Ops Program) to
help Participants that are experiencing extreme events meet customer demand through a
regional resource adequacy (RA) Program. This work has been led by the Steering Committee
with help from subject matter experts from each participating entity and oversight from the
Executive Committee. At this point, the Steering Committee has documented design details
that enable the next project phase. The Steering Committee fully recognizes that the design
will likely be updated and evolve as the RA Program is stood up; the design proposed here is
a starting point and does not solve every issue facing the region (energy adequacy, climate
change, etc.), but is a significant and important incremental step toward increased regional
coordination, which will better position the region to continue to tackle these big issues.
Phase 2A:
Preliminary
Design
Oct 2019 – June
2020
Phase 2B: Detailed
Design
July 2020 – August 2021
Phase 3B
January 2023 –
Stage
0
Interim RA Program
Stage
1
Non-binding Forward
Showing Program
Stage
2
Binding Forward
Showing Program
Stage
3
Binding Forward Showing Program with full Operational Program
Fully functional by 2024
Phase 3A
September 2021 – December
2022

Figure ES-1. RA Program development project timeline.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Regional RA Programs have been developed across North America, and throughout the
world, to ensure reliability by providing a regional framework that enables Participants to
leverage load and resource diversity benefits by meeting their collective needs jointly rather
than individually. It also establishes a robust, standardized, and transparent view of regional
loads and resources.
The documents provide a proposed design for a capacity-based RA Program. While this is a
detailed design document, there is still work to be done in the next phase to add and refine
detail of the program through the implementation phase.
While there are many ways to improve reliability and many forms of RA (capacity, flexibility,
energy), this program will focus on creating a capacity RA Program with a demonstration of
deliverability. Additional adequacy programs may also be necessary and anticipate the need
for such additions following the implementation of the capacity program. The region may
also benefit from other forms of coordination, and while the structure and processes
associated with the RA Program may serve as foundational building blocks to additional
regional coordination, the NWPP and its Participants are only working to implement the
capacity RA Program at this time. If additional programs are desired, a similarly discrete
decision and implementation process would need to be undertaken to design and implement
such programs. The proposed RA Program does not replace or supplant the resource
planning processes used by states or provinces or the regulatory requirements of the Federal
Energy Regulatory Commission (FERC), North America Electric Reliability Corporation (NERC),
or Western Electricity Coordinating Council (WECC). The program is designed to be
supplemental and complementary to those processes and requirements.
ES2. Resource Adequacy Program
Benefits
The RA Program provides benefits of enhanced coordination and increased visibility and
transparency across the regional power system. It seeks to enhance and increase reliability for
the system while maintaining existing responsibilities for reliable operations and observing
existing frameworks for planning, purchasing, and delivering energy. Current planning and
procurement to meet RA needs is handled by individual entities under the oversight of
regulators, cooperative boards, and city councils. Typically, individual entities develop plans
and procure resources that are sufficient to meet their forecasted peak load requirements
plus a stipulated planning reserve margin (PRM) or other estimates of uncertainty. In order to
meet those requirements, entities rely on combinations of self-owned generation, bilateral
contracts, planned market purchases, and available transmission capacity. This entity-by-
entity planning framework is sufficient to meet regional RA needs if (and only if):
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 9 of 254
1. Each Load Responsible Entity (LRE)1 calculates its own generation and transmission
needs using a robust methodology;
2. Each LRE builds, or enters into firm contracts with, physical resources and acquires the
sufficient transmission to meet its own needs;
3. New resources are approved in a timely manner, relative to utility needs;
4. LREs do not collectively rely excessively on “market purchases” that exceed the physical
capability of the Western resource and transmission systems to meet their service
obligations; and
5. LREs have accurately (and consistently) assessed the capacity contribution of their
resources.
If these criteria are not met, the total generation and transmission capacity available to the
region could fall below what is required to maintain reliability. Today, the individualized
nature of the current planning framework can make it difficult for regulators, board members,
stakeholders, and utilities to understand whether, where, and when new capacity is needed in
the region. The RA Program would augment these existing frameworks to increase visibility
into the true status of resources and transmission in the region and work to fill in these gaps.
Further, even if the region had enough capacity installed to meet projected needs, without
the RA Program there is no guarantee that capacity or firm transmission for deliverability is
appropriately contracted to meet the region’s needs in the most critical hours. Without
regional coordination, the footprint’s capacity could be contracted to other regions
experiencing ever-growing capacity shortfalls or may not be scheduled in such a way as to
meet the needs of neighbors within the footprint without the centralized communication and
coordination provided by the proposed RA Program.
One of the key benefits of the program is its ability to unlock the load and resource diversity
within the region. By ensuring availability and access to that diversity via the Ops Program,
LREs participating in the program (Participants) have the potential to carry less PRM going
into a peak season than they would otherwise have to carry on a stand-alone basis. For
example, the Ops Program will allow Participants to maximize the benefit of the load diversity
across the region during periods of which one Participant is peaking and another Participant
is experiencing lower load levels. In addition, during times when VERs are performing above
their accredited levels or Participants are experiencing a low level of forced generation
outages, that additional capacity may be made available to deficient Participants by the Ops
1 An LRE is an entity that (i) owns, controls, and/or purchases capacity resources, or is a Federal Power
Marketing Agency, and (ii) has the obligation, either through statute, rule, contract, or otherwise, to
meet energy or system loads at all hours. Subject to the aforementioned criteria, an LRE may be a load
serving entity (“LSE”) or either an agent or otherwise designated as responsible for an LSE or multiple
LSEs or load service under the RA Program.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 10 of 254
Program during times of generation shortfall, excessive forced outages (generation and
transmission), or load excursion.
The Ops Program allows Participants to collectively manage periods of risk of capacity
shortfall by prescriptively sharing available capacity and deliverability plans.
As designed, the RA Program will help provide transparency, regional insights, and
coordination as the region collectively plans for the future.
ES3. Program Design
The RA Program design and implementation will have two components: an FS Program and
an Ops Program. The FS Program establishes regional metrics for the footprint, the qualified
capacity contribution (QCC) and effective load-carrying capability (ELCC) of various resources,
deliverability expectations, and determines the periods for demonstrating adequacy. The FS
Program ensures the footprint has enough demonstrated capacity, well in advance of
required performance, to meet the established reliability metrics.
The Ops Program creates a framework to provide Participants with pre-arranged access to
capacity resources in the Program footprint during times when a Participant is experiencing
an extreme event. An extreme event could be when a Participant’s load is in excess of their FS
forecast or resources (generation and transmission) are experiencing unexpected outages;
this portion of the program unlocks the footprint’s load and resource diversity. The Program
seeks to achieve a balance between planning in a reasonably conservative manner but also to
provide flexibility in order to protect customers from unreasonable costs.
ES4. Governance
The NWPP and the Steering Committee have developed a straw proposal to address
governance of the future RA Program, which is critical for successfully launching the binding
stages of the program (i.e., Stages 2 and 3). In order for the changes contemplated by the
proposal to be understood, it is helpful to understand the existing governance and structure
of the NWPP Corporation, referred to as NWPP, today. Currently, NWPP provides a number of
contractual services; particularly, services to facilitate and administer the NWPP Agreement
and other major multilateral agreements (e.g., NorthernGrid, Pacific Northwest Coordination
Agreement). These programs and agreements exist outside of the NWPP: these agreements
are not governed by the existing NWPP Board of Directors, nor are committees created within
the auspices of the NWPP bylaws. Currently the NWPP does not have members, rather the
agreements to which it provides services have signatories that have traditionally been
referred to as ‘members of the NWPP.’ Additional information about the current structure of
the NWPP can be found in the straw proposal.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 11 of 254
This straw proposal includes a number of proposed changes to the NWPP that are driven by
FERC’s oversight of certain elements of the RA Program and the NWPP’s proposed role in
administering the RA Program. Under the NWPP’s proposed role, the NWPP would become a
“public utility” as defined by the Federal Power Act. Because certain RA Program elements will
be subject to FERC oversight, the NWPP will also need to meet specific independence
requirements established by FERC. Independence is understood as financial independence
from individual Participants and classes of Participants in order to ensure that such aspects do
not allow for undue discrimination for the NWPP. In addition, committees related to the
governance of the RA Program would be chartered through updates to the NWPP’s bylaws,
including the creation of an RA Participants’ Committee (RAPC) and a Committee of States,
with the potential for additional stakeholder committees to be created as determined
necessary and prudent.
In addition to continuing to provide various contractual services that the NWPP currently
provides, the NWPP would be the primary entity responsible for offering RA Program services,
providing administrative and facilitation support for the governance and administration of the
Program. The NWPP would rely on the expertise, experience, and input of the Program
Operator (PO) to provide the actual operational services and technical expertise for the RA
Program. The NWPP will also work with an Independent Evaluator (IE) to review program
design and operations.
Members of the RAPC are anticipated to be LREs who elect to join the RA Program voluntarily
(recognizing that future regulatory changes could alter the voluntary nature of the program
for certain entities). The LRE concept is intended to allow flexibility for participation, enabling
the variety of scenarios the footprint may encounter (e.g., a Power Marketing Administration,
marketer, or other such service provider assuming the obligations of one or more entities).
Additional detail related to program governance, timing of FERC filing, committees, etc. can
be found in the straw proposal.
ES5. Forward Showing Program
The FS Program aims to provide reliability benefits (increased visibility, transparency,
consistent application of metrics and methodologies) while working within existing systems
and bi-lateral market frameworks to the extent possible. Importantly, the autonomy of the
Participants will be preserved. Participants will continue to be responsible for determining
what resources to use to meet the regional metrics, working with their regulators where
applicable, and independently conducting resource planning as may be required. All entities
will maintain their current reliability obligations and the RA Program will work within the
existing Open Access Transmission Tariff (OATT) framework. The program will be voluntary
(absent any contractual or other regulatory requirements) – entities will choose to join the
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 12 of 254
program and opt in to binding consequences for non-compliance. Table ES-1 presents a
summary of key components of the FS Program.
Table ES-1 Summary of RA FS Program.
NWPP RA FS Program Snapshot
Program Structure
Bilateral; Participants will continue to be responsible for determining
what resources and products to procure from other Participants or
suppliers.
Compliance
Periods
Two binding seasons: Summer and Winter. Fall and Spring seasons are
advisory (no penalties for non-compliance).
FS Deadline
Participants will demonstrate compliance with FS reliability metrics
seven months in advance of the start of the binding seasons; if notified
of deficiency by the PO, entities will cure issues by three months prior
to the start of the binding season.
Reliability Metric FS Program is designed to identify the capacity needed to meet a 1 day
in 10 years loss of load expectation target.
Load Forecasting
Entities will forecast their own loads, working with the PO to use
acceptable forecasting methodologies. The PO will use load forecasts
and historical data to identify a P50 (1-in-2) peak load for each month
in the binding season; the highest monthly P50 will be used for all
months of that season.
PRM
Seasonal PRM will be determined for Summer and Winter seasons and
expressed as a percentage of each Participant’s identified seasonal P50
load forecast.
Resource Capacity
Accreditation
Wind and Solar Resources: ELCC analysis.
Run-of-River Hydro: ELCC analysis.
Storage Hydro: NWPP-developed hydro model that considers the past
10 years generation, potential energy storage, and current operational
constraints.
Thermal: Unforced capacity (UCAP) method.
Energy Storage and Energy Storage Resources hybrid resources:
Determined by operational testing until higher penetrations show a
need for a performance-based methodology.
Demand Side Resources: Operational testing and historical performance.
Transmission
Rely on existing OATT frameworks to facilitate transmission-related
requirements in FS and Ops. Will not infringe on Transmission Service
Providers’ and Balancing Authorities’ responsibilities, nor diminish
Participants’ OATT responsibilities.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 13 of 254
NWPP RA FS Program Snapshot
Demonstrates deliverability of resources claimed in the FS on NERC
priority 6 or 7 transmission (firm, conditional firm, network service – in
some conditions); demonstrate at FS deadline having procured or
contracted for transmission rights to deliver at least 75% of the
resources (or contracts) claimed in the FS portfolio from source to load.
When sharing is forecasted in the Ops Program, prepare to
demonstrate firm transmission for resources not previously shown to
have NERC priority 6/7 transmission.
Payment for
Noncompliance
Deficiency payment based on cost of new entry for a new peaking gas
plant.

ES6. Operational Program
In the Ops Program, the PO monitors the Participants’ forecasted load, uncertainty, and
reserve requirements, along with forced outages and VER performance, to determine when a
Participant may not have sufficient capacity to cover the projected demand. When a
Participant is forecasted to be deficient relative to their FS projection, the PO will initiate a
sharing event and call on other Participants that have prescriptively held back capacity and
can deliver energy to the deficient Participant(s). The FS Program will determine the baseline
values for the components of the Sharing Calculation (e.g., P50+PRM, baseline forced outage
rate, etc.) while the Ops Program will determine real-time differences in these values to
initiate a qualifying sharing event.
The Ops Program is implemented through sequentially comparing forecasts to the FS metrics
beginning six days before the preschedule day, identification of sharing events and required
capacity holdback on the preschedule day, and energy deployments on the operating day
(OD). The sharing calculation is performed using Participant provided data updated on at
least a daily basis from six days before preschedule, through the preschedule day for
identification of potential sharing events, and the data is updated hourly on the OD to inform
actual sharing.
Similar to the FS Program, the Ops Program aims to provide these diversity and reliability
benefits within existing frameworks, to the extent possible. Participants will settle any
exchanges or energy delivery bilaterally (using agreed-upon index-based prices). Energy will
be scheduled on transmission and delivered through existing systems. All Participants will
maintain their current reliability obligations. The Ops Program is not a new market, rather it is
an option available to Participants to assist in maintaining reliability during extreme events.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 14 of 254
ES7. Next Steps
As seen in Figure ES-1, we are at the end of Phase 2B: Detailed Design and planning to move
to Phase 3A this summer. We are working with stakeholders and potential interested RA
Program Participants to develop understanding and interest in the RA Program. Based on the
staging of functionality (pink bubbles in Figure ES-1) we plan to pursue the first Non-Binding
FS season in Winter 2022, meaning we need to begin data collection and modeling in Fall
2021. The Stage 1 Non-Binding seasons will serve as a “beta-test” for the program design
proposed in the attached documents.
The Steering Committee has held quarterly meetings with a Stakeholder Advisory Committee
(SAC) that includes representation from many sectors, regulatory bodies, and industry groups.
Through that process, the SAC has provided comments on program design and process. The
Steering Committee has successfully incorporated many of the suggestions into the detailed
design provided here, such as a commitment to analyze low water years and their effect on
the capacity contribution of storage hydro, making space for specific contracting
mechanisms, and hosting several technical workshops to dive deeper into subjects such as
state Integrated Resource Plan interplay, demand response, and program benefits.
After more than two years of hard work designing a revolutionary program to meet
increasingly dire regional needs, the NWPP RA Steering Committee is ready to begin
implementation of the program in late summer with the following anticipated activities:
• Contracting with and onboarding a PO to assist in implementing the program.
• Inviting LREs from across the West to participate in the next phase (3A) – this is an
expansion of participation as compared to past project phases, which were only open
to NWPP Agreement signatories. This sign-up period is for Stage 1 only – there will be
an offramp and separate sign up for the binding Stage 2.
• Collecting and validating data from 3A Participants to run modeling to arrive at
adequacy metrics (PRM and resources’ QCCs) for a first non-binding FS deadline in
Spring 2022 (for Winter 2022).
• Advances at NWPP to support the non-binding and future binding RA Program
activities and governance, including updates to board structure, bylaws, and staffing.

As we are in the midst of what many believe may be a capacity-tight summer season, the
NWPP is again facilitating the ‘interim’ RA Program, as was available in both Summer and
Winter 2020. The program provides communication and best-effort support to entities
experiencing capacity deficits and was utilized once during Summer 2020.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 15 of 254
The Steering Committee and NWPP appreciate the continued support of participating entities
and executives, state and federal regulators, and regional stakeholders and is looking forward
to beginning implementation shortly.

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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 16 of 254

Resource Adequacy Program
Development Project

Governance

JUNE 2021

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 17 of 254
SECTION 1. GOVERNANCE: TABLE OF
CONTENTS
Introduction ............................................................................................................................................................. 19
Governance – Actors and Participants ........................................................................................................... 23
Board of Directors .................................................................................................................................... 23
Board of Directors Transition ...................................................................................................... 24
Board of Directors Duties Common to all NWPP Services ............................................... 25
Board of Directors Duties for Specific Programs or Functions ....................................... 27
Board of Directors Limitations for the RA Program ............................................................ 28
Committee Nominating the BOD ....................................................................................................... 29
Makeup of the Nominating Committee .................................................................................. 29
Selection of Sector Representatives to the Nominating Committee ........................... 30
Operation of the Nominating Committee .............................................................................. 31
BOD Nomination Recommendations and Election ............................................................. 32
Resource Adequacy Program Participants ...................................................................................... 33
Resource Adequacy Participant Committee .......................................................................... 34
Exit Provisions ................................................................................................................................... 36
Resource Adequacy Program Operator ........................................................................................... 38
Independent Evaluator ........................................................................................................................... 39
Other Committees and Structural Functions ................................................................................. 40
Committee of States ....................................................................................................................... 40
Program Review Committee........................................................................................................ 40
Cost Allocation Principles ...................................................................................................................... 45
Assigning Costs Incurred to RA Program ............................................................................... 45
Allocating Costs to RA Program Participants ........................................................................ 45

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 18 of 254
INTRODUCTION
The Northwest Power Pool (NWPP) and the Steering Committee have developed the
following straw proposal for the future state of the NWPP with governance, structure, and
function changes associated with implementation of Resource Adequacy (RA) Program Stages
2 and 3; this document does not address: 1) transition issues and steps that would need to be
taken to implement the recommended changes (transition issues and procedures will be
addressed in a future proposal; and 2) governance and structural approach for RA Program
Stage 1 (also referred to as Phase 3A). This proposal should be interpreted as a starting point.
This recommendation will be further refined in future phases.
Currently, NWPP provides a number of contractual services. The diagram in
Figure 1-1 presents the key services and their relationship with the current Board of Directors
(BOD) and staff.
This proposal includes a number of changes to the NWPP, including a role for the NWPP to
administer the RA Program and to meet: (i) the necessary requirements for being a public
utility under the Federal Power Act and the Federal Energy Regulatory Commission’s (FERC)
regulations; and (ii) FERC’s independent board of directors criteria, which will be very helpful
in obtaining FERC acceptance of the RA Program.2 For purposes of this straw proposal,
independence should be understood primarily as financial independence from
Participants and classes of Participants in order to ensure that any such interests do not
contribute to undue discrimination by the NWPP. In addition to prohibiting direct
financial conflicts, however, the NWPP would also impose criteria intended to eliminate other
types of conflicts-of-interest, as well as situations that lead to an appearance of bias.3
In addition to continuing to provide or facilitate the various services that the NWPP currently
delivers, the NWPP would be the primary entity responsible for offering RA Program services,
would provide administrative support for the governance and administration of the RA
2 We note that neither the Federal Power Act, FERC’s regulations, nor legal precedent establishes a clear
requirement that non-Regional Transmission Organization/non-market regional programs such as the RA
Program require an independent BOD. However, FERC will most likely look more favorably on the RA Program
with an independent BOD.
3 With respect to indirect financial conflicts or conflicts of interest that may arise from outside activities, secondary
employment, or other activities, the NWPP should follow corporate best practices in order to instill a sense of
confidence in the NWPP. In general, the NWPP should adopt policies that prohibit BOD members from engaging
in any outside business activity that interferes or materially decreases the Director’s impartiality, judgement,
effectiveness, productivity, or ability to perform Director’s duties and functions at NWPP. In some instances, such
conflicts may be waivable with notice and consent.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 19 of 254
Program, and would rely on the expertise, experience, and input of the Program Operator
(PO) to provide the actual operational services for the RA Program. The diagram in Figure 1-2
is an illustration of the proposed future structure of NWPP.
The following sections outline aspects of how the Steering Committee anticipates the
changes shown in Figure 1-2 will be implemented. Generally, this includes the evolution of
the existing NWPP BOD to an independent board to serve as the ultimate decision-making
body for future governance and supporting committees to accomplish all other ongoing
functions. Directors on the BOD will be nominated by a sector-representative committee, the
Nominating Committee (NC), which will seek and vet potential Directors before proposing a
slate of new Directors to the current BOD for confirmation.
A RA Participants Committee (RAPC) will work with support from the NWPP and a PO to
consider and recommend design updates, compliance considerations, and other daily
program operations; these recommendations will stand unless challenged to or by the BOD.
Another sector-representative committee, the Program Review Committee (PRC), will field
recommendations for changes to program design and will document proposed changes and
run public and committee comment processes to inform consideration of those
recommendations by the RAPC and BOD.
State regulators and energy offices have always served an important role in RA, and the
proposed design recommends a committee exclusively for state representatives, a Committee
of States (COS). The scope and role of this committee will be informed through ongoing
collaboration with state representatives in upcoming phases.
The Steering Committee anticipates the need for additional committees or subcommittees to
support program operations and continuous improvement. Additional committees, their
scope and authority will be considered throughout implementation phases and into the
future, but it is not currently anticipated that their addition would substantially alter the scope
or substance of the committees recommended in later sections.
The PO, an entity with extensive RA Program implementation, operation, and modeling
experience, will report to the independent BOD and will work collaboratively with the NWPP
to bring their expertise to all supporting committees. The NWPP will also work with an
Independent Evaluator (IE) to review program design and operations.
The governance framework will be reviewed after 3-5 years of operations to ensure it is
sufficiently meeting the needs of the Participants and the region.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 20 of 254
NWPP Board of Directors
Self perpetuating
Semi-independent
NWPP CEO
NWPP Staff
NWPP CORP
NWPP Agreement (NWPPA)
Operating
Committee
Transmission
Planning
Committee
Reserve
Sharing
Committee
Membership
Agreement
All members sign
NWPPA to become
members Individual NWPPA members sign
General Service Agreements with
NWPP to provide services1 to implement NWPPA.
Some members sign work orders for discrete services.
Coordinating
Group (for
PNCA)
Reserve Sharing
Agency Agreement
Makes NWPP Corp NERC/WECC
compliance entity for BAL-002.
Signed by subset of NWPP
members (BAs in RSG program)
Western Frequency
Reserve Sharing
Agreement (WFRSG)
Parties are currently a subset of
NWPPA members. Open to non-
NWPPA members.
Members contract with
NWPP for
agreement execution
services1
Members contract with NWPP for
agreement execution services1
KEY:
Long Dashes and Colors – entities and agreements
Short Dashes – contractual relationships (described in captions)
Solid Line – reporting structure (loose – likely needs more discussion and procedures/policies)
NorthernGrid
Project coordinator for
compliance with FERC
transmission planning
requirements (e.g. Order 890,
Order 1000)
Members contract with
NWPP for
agreement execution
services 1
Other Services
The NWPP provides many additional services to
NWPPA signatories under contracts and agreements
not specifically enumerated here; four major ongoing
efforts are identified as examples to illustrate the
before/after structure.
1 Services provided by NWPP CORP to members of the NWPPA include:
• Staffing and administrative support to enable the NWPPA signatories to implement the NWPPA;
• Coordination and documentation activities for standing NWPPA committees;
• Facilitation of member activities and monitoring of compliance with committee/program rules and standards;
• Acting as agent for member compliance with various reliability standards (e.g. above agreements); and
• Developing training modules and providing individual member training platform to train member employees and employees of
member RCs.
For additional information on services provided by the NWPP CORP, see Appendix A.

Figure 1-1. Diagram of NWPP today.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 21 of 254
*relationship dependent
upon discussions
with Regulators
NWPP Board of Directors
Independent
RA
Participants
Committee
(RAPC)
Committee of
States (COS)
Nominating
Committee
Sector Representative
NWPP CEO
NWPP Staff
RA Program
Operator
NWPP CORP
NWPP Agreement (NWPPA)
Operating
Committee
Transmission
Planning
Committee
Reserve
Sharing
Committee
Membership
Agreement
All members sign
NWPPA to become
members
Individual NWPPA members sign
General Service Agreements with
NWPP to provide services to
implement NWPPA.
Some members sign work
orders for discrete services.
Coordinating
Group (for
PNCA)
Contracted with NWPP CORP
Direct reporting lines to
BOD and RAPC (when
BOD powers are delegated there)
KEY:
Long Dashes and Colors – entities and agreements
Short Dashes – contractual relationships (described in captions)
Solid Line – reporting structure (loose – likely needs more discussion and procedures/policies)
Reserve Sharing
Agency Agreement
Makes NWPP Corp NERC/WECC
compliance entity for BAL-002.
Signed by subset of NWPP
members (BAs in RSG program)
Western Frequency
Reserve Sharing
Agreement (WFRSG)
Parties are currently a subset of
NWPPA members. Open to non-
NWPPA members.
Members contract with
NWPP for
agreement execution
services
Members contract with NWPP for
agreement execution services
NorthernGrid
Project coordinator for
compliance with FERC
transmission planning
requirements (e.g. Order 890,
Order 1000)
Members contract with
NWPP for
agreement execution
services
Other Services
The NWPP provides many additional services to
NWPPA signatories under contracts and agreements
not specifically enumerated here; four major ongoing
efforts are identified as examples to illustrate the
before/after structure.
Program Review
Committee
(PRC)
Sector
Representative
Takes Public
Comment
Independent
Program
Evaluator
Contracted with NWPP CORP
Direct reporting line to
BOD. Evaluations available to
Participants, Regulators, Public
Figure 1-2. Diagram of Future NWPP.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 22 of 254
GOVERNANCE – ACTORS AND
PARTICIPANTS
Board of Directors
The following elements are proposed for the future NWPP BOD:
• There will be one independent BOD for the NWPP.
o Currently, there is one BOD for NWPP, which is semi-independent (i.e., some
members would likely be determined to be financially independent, and
others would not).
• The BOD will oversee the RA Program as well as those responsibilities currently
assigned to the BOD for the other services provided by or facilitated by the NWPP.
• The BOD will be composed of up to five to seven persons, but no less than three
persons.
o Currently, there are five members of the NWPP BOD.
• Directors are selected and nominated by the NC (see Section 1.2 for more information)
to three-year terms and confirmed by the Directors which are currently seated and
whose terms are not expiring.
o Currently, the Directors are selected by the current BOD without term limits.
• The terms of the Directors will be staggered in order to maintain continuity.
• A Director may serve up to two three-year terms which may be served non-
consecutively.
• A Director who is not term-limited but wishes to be considered for an additional term
must provide appropriate notice of this intention.
• The NC will interview the Director whose term is expiring regardless of whether the
Director is seeking re-appointment. If the Director is seeking re-appointment, the
purpose is to determine if the NC wishes to advance the Director for another term
without interviewing other candidates; if the Director is not seeking re-appointment,
the purpose is an exit interview.
• The NC will determine whether it wants to re-nominate the departing Director without
interviewing other candidates.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 23 of 254
• If the NC does not decide to re-nominate the departing Director, then it should seek to
identify at least two qualified candidates to interview, in addition to the sitting
member.
• The NWPP Chief Executive Officer (CEO) is proposed to be a voting member of the
BOD, provided the CEO also passes the independence requirements.

Board of Directors Transition
Specific transition issues relating to the current NWPP BOD will be addressed in a future
version of this proposal; however, it has been recommended by the existing NWPP BOD and
staff that this proposal address a specific approach for how the existing NWPP BOD can
ensure its fiduciary duty to the current NWPP.
The future RA Program and the governance and structural changes have the potential to
change the overall shape, direction, and priorities of the NWPP and how the NWPP delivers
the services that it is currently responsible to provide. As such, the current NWPP BOD must
support and approve the proposal to transition to an independent BOD.
Allowing for limited duration, limited scope engagement by a limited number of current BOD
members is a vehicle for giving the current BOD trust in the transition so that they can
confidently support the actions needed for the NWPP to evolve.
The following approach is recommended for achieving these objectives:
• Two supplemental seats to the proposed NWPP BOD would be allocated to two current Directors
who volunteer to be considered (e.g., assuming the new NWPP BOD consists of five Directors,
the two supplemental seats would bring the total to seven);
• The two Directors for the supplemental seats would be selected by the NC (discussed below);
the NC would apply financial independence criteria in order to select the two supplemental
Directors;
• The two supplemental seats would serve in a strictly advisory capacity for RA Program matters
but would serve in their regular capacity for all other programs and services provided by the
NWPP;
• The two supplemental seats would serve a maximum of two, three-year terms (not staggered);
and
• Any current NWPP BOD Directors can apply for the regular seats on the future BOD and would
be considered along with all other qualified candidates considered by the NC.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 24 of 254
Board of Directors Duties Common to all NWPP
Services
1) At all times the BOD will act in the best interest of NWPP in its management, control, and
direction of the general business of NWPP.
The current BOD has this same fiduciary duty, which is derived from corporate law.
2) The BOD will exercise an appropriate degree of independence from Participants.
The current BOD is not structured as an independent BOD, so this would be a change.
3) In reaching any decision, the BOD Directors must execute the duties of the BOD in an
unbiased, professional, respectful, and collaborative manner that promotes integrity,
teamwork, trust, and a professional work environment.
This is not an explicitly codified requirement for the current BOD but is exercised in
practice.
4) Unless otherwise restricted (see Section 1.1.4), the BOD will have full authority to change
the bylaws.
In general, the current BOD has this same authority, derived from corporate law. In the
case of the current set of governing documents, the committees created by the NWPP
Agreement are not part of the current bylaws and thus cannot be changed by the
current BOD.
5) The BOD has the authority to review the performance of the corporation, its officers, and
staff, unless specifically delegated to NWPP staff. When evaluating the performance or
compensation of the CEO, the CEO will be appropriately excluded from deliberations of
the other BOD members. With respect to duties delegated to NWPP Staff, the BOD may
rely on reports from NWPP Staff but must continue to exercise oversight over those
duties. This BOD obligation is relatively standard. The day-to-day decisions about hiring,
salaries, executive management, etc., are the responsibility of the CEO.
The current BOD is similarly responsible for evaluating the performance of the
corporation, its officers, and staff. Currently the CEO is not a Director and thus need
not be excluded from deliberations about CEO performance.
6) The BOD has the authority to evaluate the performance of individual BOD members and
the BOD as a whole. When evaluating the performance of individual BOD members, that
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 25 of 254
BOD member will be appropriately excluded from deliberations of the other BOD
members.
The duty to evaluate the performance of individual BOD members is an existing BOD
obligation.
7) The BOD will review and approve the financial position of the NWPP (including the RA
Program), including its budget, expenses, and projected expenses, to ensure the NWPP is
financially sound and has the appropriate funding to meet its contract requirements.
The existing BOD has this same obligation.
8) The BOD will review the goals and directions set by the NWPP, its programs and
committees to understand the impact on NWPP and its employees, including the impact
on longer-term employment for NWPP employees, corporate risk, and potential impacts
on the structure of the NWPP.
The existing BOD has this obligation. Here, “goals and directions set by the NWPP”
refers to the goals and directions set by the signatories to the NWPP Agreement
through the programs and committees set up under that agreement; the NWPP has a
contractual obligation to support those programs and committees.
The BOD currently emphasizes that the NWPP is currently viewed as a service or
consulting organization to facilitate the goals of the signatories to the NWPP
Agreement. The obligation to continue such services will continue even upon
development of an RA Program.
9) The BOD will ensure the NWPP has appropriate insurance for its business operations,
Directors, officers, and staff.
The existing BOD has this same obligation.
10) The BOD will ensure the NWPP has appropriate retirement funding as established by the
corporate retirement plan.
The existing BOD has this same obligation.
11) The BOD will ensure the NWPP has appropriate employee benefits as established by the
corporate benefit plan.
The existing BOD has this same obligation.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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12) The BOD will ensure the NWPP is meeting all its legal requirements and that it has
sufficient legal resources to support regulatory process and regulatory filings.
The existing BOD has this same obligation, though the scope of the regulatory filings
under the NWPP’s purview would be expanded if an RA Program were established;
legal requirements include tax filings (nonprofit status) as well as regulatory filings.
13) The BOD will hire the officers of the NWPP and address succession plans.
The existing BOD has this same obligation.
14) The BOD will elect from its membership a Chair and Vice Chair for two-year terms.
The current NWPP Bylaws state that the NWPP will have a BOD Chair and a Vice-Chair.
15) The BOD will meet at least three times per calendar year (in-person or virtual) and
additionally upon the call of the Chair or upon concurrence of at least a majority of
Directors.
BOD meeting requirements for the current BOD are established by the Bylaws and
require the BOD to conduct at least one annual meeting and one additional regular
meeting each year; special meetings are conducted upon the call of the Chair or upon
concurrence of at least three Directors.
16) Directors will receive compensation and be reimbursed for actual expenses reasonably
incurred or accrued in the performance of their duties.
Current Directors are reimbursed for actual expenses and receive compensation for
meeting attendance.

Board of Directors Duties for Specific Programs or
Functions
The BOD will authorize filings with regulatory bodies, except for the RA Program when the
BOD will authorize, and the NWPP will submit filings only after consideration by the RAPC. If
the RAPC approves an action and such action is not appealed to the BOD, the action is
deemed to be approved by the BOD, and NWPP is authorized to submit any applicable
required regulatory filing(s). Any action, or inaction, taken by the RAPC may be brought
before the BOD for ultimate resolution. Currently the NWPP makes regulatory filings on
behalf of program Participants who have named the NWPP the agent for compliance with
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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certain NERC reliability standards; NWPP Staff works with Reserve Sharing Group and
Western Frequency Response Sharing Group participants to coordinate such filings.
1) BOD meetings for the RA Program will be open and noticed to all stakeholders for all
meetings except when in executive session. Executive sessions (open only to Directors and
to parties invited by the Chair) will be held as necessary upon agreement of the BOD to
safeguard confidentiality of sensitive information.
Current BOD meetings do not involve stakeholders and are not open to the public.
2) The Chair of the BOD will grant any stakeholder’s request to address the BOD during open
public meetings for a prescribed period of time with respect to RA Program.
Current BOD duties do not require a stakeholder process.

Board of Directors Limitations for the RA Program
Regarding the RA Program, the BOD will be prohibited from engaging in the following:
1) Changing the Participants’ existing functional control and responsibility over their
generation and transmission assets.
a) Participants will retain full autonomy and responsibility to ensure the reliable and
efficient planning and operation of their transmission systems.
b) Participants will retain existing autonomy and responsibility over transmission
operations and transmission service, including the administration of open access
transmission tariff (OATT) requirements and transmission planning functions.
c) Participants will retain full autonomy and responsibility related to the operation of
their generation resources, as well as the development of resource plans and
ongoing compliance with those plans. This provision includes a restriction that the
BOD will not impose must-offer obligations on any Participant or their resource(s).
d) Participants who administer a Balancing Authority (BA) will retain responsibility for
ensuring compliance with applicable reliability standards within their BA
boundaries, and any other reliability standard requirements for applicable NERC
functional designations.
2) Administering OATT service, engaging in BA operations, imposing transmission
planning requirements or assuming any transmission planning responsibilities.
3) Taking action to form an organized market, including a capacity market, or establishing
a Regional Transmission Organization, unless such action was also approved by the
RAPC.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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4) In response to a failure to meet program requirements, requiring anything beyond the
imposition of financial or penalty consequences, the limitation or suspension of
participation, or other similar measures.
These limitations will be addressed in the updated bylaws of the NWPP by
requiring additional committees’ support (e.g., RAPC, COS) for bylaw changes that
expand the scope the BOD and the NWPP to include such activities.
Committee Nominating the BOD
An NC is proposed to be used for selecting the members of the BOD. The following
proposal is based in large part on the NC procedures that have been successfully
used for the Western Energy Imbalance Market. The BOD will be selected by a NC
comprised of certain stakeholder representatives. This proposal explains the
selection and composition of the NC, how the NC will select a slate of nominees for
each open position, and how that slate of nominees will be subject to a vote of
approval on the slate by the BOD. The NC will nominate a slate with one nominee
for each open seat on the BOD for which the term is scheduled to expire.
The NC is responsible for nominating proposed BOD members for approval by the sitting
BOD. The NC is also responsible for recommending compensation for the BOD. The NC is the
primary committee responsible for identifying a recommended nominee or nominees for
open positions on the BOD, working with the NWPP staff and an executive search firm.
Makeup of the Nominating Committee
• The NC will be comprised of 12 individuals from stakeholder sectors and such sectors
will have the following designated number of seats on the NC and the following voting
designation.
o Proposed sectors include:
▪ RAPC/Participants, ensuring appropriate representation among these
types of Participants:
• Investor-owned Utilities (IOUs) (2) - voting
• Cooperative-owned utilities (COUs (2) - voting
• Retail Competition Load Responsible Entity (LRE) (1) - voting
• Federal Power Marketing Administration (1) - voting
▪ Independent power producers/marketers (1) - voting
▪ Public interest organizations (1) - voting
▪ Customer advocacy groups (1) – voting
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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▪ NWPP member (not on RAPC) (1) - voting
▪ BOD (a member who is not rolling off, not the NWPP CEO) (1) – non-
voting
▪ COS (chair or vice chair) (1) – non-voting (but voting in the event of a tie)
Each sector will appoint its representatives to the committee. In the event that a particular
sector cannot reach consensus regarding their representative, the NC normal activities may
continue without a full NC. The NC will strive for and will act on the consensus of its members.
However, in the event consensus cannot be obtained, voting procedures will be utilized and
at least a simple majority must be obtained to approve a candidate to the slate. Non-voting
members are expected to share their views about the candidates and to participate fully in
deliberations.
Each sector will determine its own method of selecting a representative(s) to serve on the NC,
and the term of service. A sector may designate a term of service for multiple years if it wishes
to avoid the need to meet in the following year(s) to select a representative. The minimum
term of service will be one year.
Selection of Sector Representatives to the
Nominating Committee
Not less than 150 days prior to the scheduled expiration of any BOD member’s term, and at
other times as may be necessary to fill a vacancy on the BOD, the staff of the NWPP will
ensure that each sector of the NC has identified their respective representative(s).
The staff of the NWPP will issue a notice that the NC will be convened in parallel with the NC
representative’s sector outreach. The public notice will include a list of the NC representatives.
The purpose of this notice is to provide an opportunity for sector members to self-identify in
order to receive communication from the sector organizer.
If one or more of these sectors does not have a currently serving representative to the NC,
the staff of the NWPP will designate a person from one of the entities in the sector to serve as
a sector organizer to facilitate selection of a representative. Each sector organizer must make
reasonable efforts to notify all entities that are qualified for participation in its sector about
the initial organizational meeting or teleconference for the sector. These efforts will include
issuing, with assistance from staff, a notice no less than seven calendar days in advance of the
meeting or teleconference.
The entities in each sector should make their best efforts to amicably resolve any
disagreements about which entities belong within the sector and thus are entitled to
participate in the sector’s selection of a representative to the NC. Any disagreements that
cannot be resolved by the entities in a sector may be referred to the management of the
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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NWPP for resolution. The CEO (or his or her designee) and the General Counsel will hear from
the interested parties and make a decision. Their decision will be binding on the sector.
Within 40 days after the NWPP staff designates a sector organizer to facilitate selection of a
representative, the sector organizer will certify the choice of the sector representative. If a
sector organizer has been unable to make a certification because the sector has been unable
to reach agreement on its representative, the BOD will select a representative for the sector.
The NWPP staff will post the name and contact information of each sector representative on
its website.
Operation of the Nominating Committee
Once organized, the NC should convene no less than 100 days prior to the scheduled
expiration of any BOD member’s term to begin the process of identifying potential
candidates for each open seat, or as soon as practicable when other vacancies arise.
If a BOD member whose term is scheduled to expire has expressed a desire to be nominated
for a new term (and has not reached their term limit), the NC should determine whether it
wants to re-nominate the departing member without interviewing other candidates. If the NC
does not decide to proceed in this manner, then it would ask the executive search firm to
identify at least two qualified candidates to interview, in addition to the sitting member.
The NC will apply the following criteria in its selection process:
• Working with NWPP staff, the NC will engage and work with an executive search firm
to identify at least two qualified candidates to interview.
o The executive search firm may not consider a candidate who has a prohibited
relationship or financial interest, unless the candidate commits to promptly end
any prohibited relationship after being appointed and before exercising the
duties of the office, and to dispose of any prohibited financial interests within
six months after appointment.
• With assistance from the executive search firm, the NC will develop a job description,
job posting, identify, and select the best qualified candidates available in the United
States.
• Optimally, the NC’s selections should ensure that the overall composition of the BOD
reflects diversity of expertise so that there is not a predominance of Directors who
specialize in one subject area, such as operations or utility regulation. The following
skillsets and expertise should be considered:
o Electric industry — such as former electric utility senior executives currently
unaffiliated with any market Participant or stakeholder; present or former
executives of electric power reliability councils; present for former executives
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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from power pools; retired military officers with relevant experience; or present
or former executives of firms that perform professional services for utilities;
o Regulatory — executives or attorneys with extensive background in the
regulated utility industry, resource or transmission planning; former state or
federal regulators with applicable experience; or academics or consultants with
relevant experience; and
o General corporate/legal/financial — such as present or former management
consultants or service industry executives; present or former chief executives;
chief financial officers; chief legal officers or chief information officers of
profitmaking companies; present or former national law firm partners; present
or former senior executives of financial institutions, investment banking or
financial accounting/auditing organizations.
• In addition, the NC should give consideration to diversity with respect to race, gender,
and ethnicity.
• The NC will consider geographic diversity and no one state or sub-region in the West
should have excessive representation — meaning members whose place of residence
or work history tends to associate them with a particular Western state.
• The NC should strive to ensure that the BOD includes at least one member with
expertise in Western electric systems, markets, or utility resource planning.
• The deliberations of the NC will be confidential. The candidate selection process is
highly sensitive and candidate information, and the deliberations of the NC should not
be shared publicly. However, the NC sector representatives may confer with their
sectors to enable sector alignment and support for candidates. The NC sector
representative may communicate with their sector as part of the process of evaluating
candidates. The NC should have a common understanding about the extent to which
they will share the names of candidates in connection with a particular search (timing,
level of detail, etc.).
• The NC will meet as required to perform its responsibility.
• Except as otherwise provided here, the NC may establish its own procedures.

BOD Nomination Recommendations and Election
The slate submitted by the NC will be subject to approval by the BOD in an open session. If
the decision occurs before the end of the expiring terms, the BOD Director(s) whose terms are
expiring will be recused from the approval decision. The BOD must accept or reject the slate
as a whole.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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For example, assuming two sitting BOD members’ terms are expiring, the NC would be
convened and would work with the executive search firm to screen and identify qualified
candidates. Through this screening, review, and interview process, the NC will select two
qualified candidates and these candidates will comprise the slate of candidates recommended
to the sitting BOD for approval. The sitting BOD will vote on the slate as a whole, either
approving or rejecting.
If the slate is accepted, the nominees will become Directors.
If the slate is rejected, the NC must re-convene and establish a new slate of nominees. The
new slate must not be identical to the prior slate, though the NC may retain one or more
nominees from a prior slate involving multiple nominees. After the NC submits its second
slate of nominees, the BOD will decide, in public session, to approve one of the two slates
that was submitted by the NC.
Resource Adequacy Program
Participants
The following are the qualifications for Participants:
1) Participants must be an LRE.
2) Participants must have either a physical transmission connection or rights to use
transmission to at least one other Participant or a trading hub used by Participant(s).
3) Participants must sign the Western Resource Adequacy Agreement (WRAA) that
includes terms and conditions and comply fully with those terms and conditions and
any other agreements necessary to facilitate the RA Program.
4) Participants may be required to be a signatory to the WSPP, formerly known as the
Western System Power Pool, or an enabling agreement given that the RA Program is
built around leveraging existing bilateral structures.
5) Participants are expected to register their entire fleet of resources that can be called on
to serve their respective loads so that the RA Program will have visibility to all
resources the Participant is relying on within the program.
6) Participants will sign a data sharing and confidentiality agreement essential for the
operation of the RA Program.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 33 of 254
Resource Adequacy Participant Committee
1) The RAPC is comprised of Participants and is responsible for developing and
recommending policies, procedures, and system enhancements related to the policies
and administration of the RA Program by NWPP.
2) Participation in RAPC is limited to Participants. Therefore, the RAPC is a committee with
limited membership; this is more conservative than what was proposed and approved
by FERC for Southwest Power Pool’s (SPP) Western Markets Executive Committee.
3) The RAPC is responsible, through its designated working groups, committees, and task
forces, for developing and recommending policies, procedures, and system
enhancements related to the policies and administration of the RA Program by NWPP
under the WRAA in the Western Interconnection. This is similar to what SPP provided
through its Western Markets Executive Committee.
4) In carrying out its purpose, the RAPC will provide the forum for Participants that have
executed a WRAA with NWPP. The RAPC can approve or reject proposed amendments
to the RA Program Tariff prior to the filing of such amendments at FERC. The RAPC can
also consider, approve, or reject program rules if such rules solely apply to the
administration of the RA Program and have no application to any other program
and/or contract service provided by NWPP. To the extent such rules do apply to any
other service provided by NWPP, the RAPC will be afforded the opportunity to provide
input to the NWPP BOD to resolve any issues. This will be accomplished by a
collaboration with NWPP on the development of RA Program provisions, business
practices, and interregional agreements to promote transparency and efficiency in the
operation of the RA Program.
5) The RAPC can evaluate and provide consultation to NWPP on the RA Program
administration budget and budget allocation to Participants, including modifications or
adjustments of the RA Program Administration Rate, in accordance with the WRAA.
There are other responsibilities that can be added to the detail as this proposal is filled
out.
6) Each Participant will appoint one representative to the RAPC. Each representative
designated will be a senior level management employee with financial decision-making
authority. The RAPC representatives will appoint the chair and vice chair of the RAPC.
7) The RAPC will form and organize all the organizational groups under its
responsibilities. Each working group, committee, or task force reporting to the RAPC
will be assigned a NWPP staff secretary, who will attend all meetings and act as
secretary to the group. Staff secretaries of all working groups, committees, and task
forces will be non-voting.
8) The quorum for a meeting of the RAPC or any working group, committee, or task force
reporting to the RAPC will be one-half of the representatives thereof, but not less than
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three representatives; provided, that a lesser number may adjourn the meeting to a
later time.
9) In the RAPC, each representative will have one vote. Voting will utilize a “House and
Senate” style approach. The “House” vote will be weighted based on each
representative’s P50 load, as determined in the FS Program (see 2.3 for additional
information on the determination of the P50 load). The P50 metric is used to allocate
requirements and benefits of the RA Program throughout both time horizons; in the
FS, it determines the FS capacity requirement, and in the Ops Program, it is a key
component of the Sharing Calculation (determining a Participants’ ability to access
pooled resources). “House” voting will use the higher of a Participant’s two seasons’
P50s (e.g., Winter-peaking Participants will use their Winter season P50 value in voting)
and will be weighted as a portion of the sum of all Participants’ higher-season P50
loads. The “Senate” vote will be equally weighted for all RAPC representatives. For a
resolution to be approved, it must pass both the “House” and the “Senate” vote.
a. Resolutions brought to the RAPC with support from the PRC will be approved
with 67% affirmative votes from both “House” and “Senate” vote tallies.
b. All other votes will require an affirmative vote of 75% or greater of both
“House” and “Senate” tallies.
c. If at any time, a single LRE is responsible for more than 25% of the total non-
coincident high-season P50 loads (creating an effective veto power), a review of
the voting thresholds would be triggered.

Table 1-1. Example of House and Senate style
voting approach
Entity P50
(MW)
P50 (House)
Weighting Vote
A 1500 3.07% No
B 9000 18.42% Yes
C 400 0.82% Yes
D 2200 4.50% Yes
E 850 1.74% No
F 3500 7.16% Yes
G 11000 22.52% Yes
H 4200 8.60% Yes
I 8700 17.81% Yes
J 7500 15.35% Yes
Total P50
Load
(MW)
48850 100% N/A

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 35 of 254
In the example presented in Table 1-1, the vote passes; the pro-rata (Senate)
vote tally is 80% affirmative, while the P50-weighted (House) tally is 95%
affirmative, since the two dissenters are small entities. If another entity (of any
size) were to vote “no,” the vote would pass for a PRC-approved vote but fail
for any other vote, as the pro-rata vote would drop to 70% affirmative, below
the 75% threshold. Similarly, if entity G dissented instead of entity E, the vote
would pass for a PRC-approved vote but fail for any other vote, as the pro-rata
vote would drop to 72.67% affirmative the vote, below the 75% threshold.
10) The RAPC is the highest level of authority for representation by Participants. The NWPP
BOD will provide independent oversight of NWPP’s administration of the RA Program
under the WRAA. If the RAPC approves an action and such action is not appealed to
the NWPP BOD, the action is deemed to be approved by the NWPP BOD, and NWPP
staff is authorized to submit any applicable required regulatory filing(s). Any action, or
inaction, taken by the RAPC may be appealed by any stakeholder to the NWPP BOD
for ultimate resolution.
11) Meetings of the RAPC are open to all interested parties; and written notice of the date,
time, place, and purpose of each meeting will be provided as described below.
However, the RAPC may limit attendance during specific portions of a meeting by an
affirmative vote of the RAPC in order to discuss issues that require confidentiality.

Exit Provisions
A Participant can exit the RA Program if they are ordered by a regulatory body (jurisdictional)
or if they determine (jurisdictional or non-jurisdictional) that exit is required to protect the
interests of their customers. A Participant could also decide that it needs to leave the
program because the Participant disagrees with a decision being made under the governance
model that affects the way the RA Program is administered or their ability to continue
participation. A Participant could decide that it needs to leave the program for various
business reasons.
The following straw proposal for exit provisions is provided for consideration:
• Participant entry and exit from the program will remain voluntary, however,
appropriate notice must be given prior to exit.
• Options for standard notice provision:
o Parties must give at least 24 months written notice prior to the beginning of the
next binding FS period. This requirement may result in more than 24 months
between when the notice is given and the actual effective date of the exit.
▪ For example, if a Participant did not want to participate for the Summer
2025 binding season, the Participant would need to give notice by June
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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1, 2023. This corresponds with the timeline for the FS Program when
Participants would be required to complete review of their inputs to the
loss of load expectation (LOLE) model, but prior to the time when the
model is run by the PO to provide the binding planning reserve margin
(PRM) for the Summer 2025 season in question].
▪ The standard notice period could be shorter than what is suggested here,
but the timing and logistics on FS and operations would need to be
worked through.
o Options for non-standard exit:
▪ The program could also include additional provisions that provide for
earlier exit under the following circumstances:
• Exit for “extenuating circumstances” (such as by order of
regulatory authority or additional circumstances to be defined) to
be assessed by the BOD and/or PO on a case-by-case basis
• Exit by fee to ensure that any unreasonable harm from earlier exit
is mitigated or compensated by the exiting Participant. The PO
would calculate the exit fee. This exit provision would only be
available if the exit fee can be calculated by the PO with a high
degree of confidence.
• If a Participant experiences a significant decrease in forecasted
peak load after the two-year deadline has transpired, they will
work with the PO, and/or third-party neutral, for the purpose of
developing an understanding of factual matters for the change, to
determine whether there are or would be any resulting impacts to
other Participants. Further consideration of what constitutes a
“significant” decrease, what solutions are available to address the
change, and how the costs of this assessment are allocated will be
considered in 3A.
o Once proper notice is provided, the withdrawing Participant will be in the
withdrawal period until exit is effective, during which the withdrawing
Participant is required to continue to comply with all requirements of the RA
Program, except, however, the withdrawing Participant will recuse themselves
from any votes or actions affecting the RA Program for timeframes that extend
beyond the withdrawing Participant’s exit effective date.
• In addition, any financial obligations that exist as of the exit date are preserved until
satisfied (e.g., the Participant has already been assessed cost of new entry penalties for
failure to meet the FS Program).
• A Participant who exited can re-enter provided their entry is negotiated with the PO to
commence consistent with the timing of the deadline for the inputs required for the
LOLE study needed in the next binding FS Program season.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Resource Adequacy Program
Operator
1) In order to provide a clear direction for the RA Program and how it can be
implemented, the following will outline how NWPP and the contracted PO will fulfill all
the required functions needed for the RA Program. The PO will report directly to the
BOD but will also interface with other committees and NWPP staff as needed to fulfill
their duties. Note that NWPP will enter into a contract with the PO that will define the
required responsibilities of the PO. Generally, it will be the responsibility of NWPP to
provide any needed general logistics and oversight of the contract with the PO to
perform FS and operations functions of the RA Program.
2) NWPP will provide all support of the governance outlined above including the
compensation for the BOD, responsibility for the expenses and logistics for all their
meetings and the committees under the BOD. The support of the contract and
compensation to the PO will be the NWPP responsibility, as well as legal and federal
regulatory support for the RA Program, including meeting all the functions required of
a public utility. NWPP will also be responsible for billing, collection and payments
under the RA Program as well as all the other current contracted programs and
services of the NWPP.
3) The PO will be responsible for the fulfillment of the contract requirements for the RA
Program including the FS and the near-term to real-time operations. These would
include modeling and system analytics, the performance or analysis of the LOLE study,
PRM analysis, qualifying capacity contributions, FS Assessments, Deliverability for
Planning & Reliability Coordination for capacity reserve adequacy, and Generation
Assessment & Uncertainty Response activity. These responsibilities will also include the
monitoring and responding in the real-time operations. The PO will calculate any
required settlements and assess penalties for noncompliance according to the penalty
calculation rules set forth in the program. To perform their functions under the
contract, the PO will have sufficient information technology resources including
systems and people to maintain the systems, meeting requirements of cyber security,
backup of data/systems, change control, and system recovery.
4) The PO will support the RAPC and other committees to provide comments, input,
solutions, and problems. The PO also could be asked to provide input to the NWPP
BOD.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 38 of 254
Independent Evaluator
The Independent Evaluator (IE) function has been identified by the current NWPP BOD, state
regulators, and the Stakeholder Advisory Committee as an important element of a well-
functioning regional RA Program to provide an outside, independent assessment of the
performance of the program. It has been identified as an element that will be important to
FERC as they consider approving the FERC-jurisdictional elements of the RA Program. It is
recommended that the IE be established on or near the conclusion of Stage 1 of the RA
Program and on an ongoing basis to provide an annual review of the RA Program. This initial
scope for the IE could change over time, but this initial recommendation is intended to
balance the need for independent review to identify continuous improvement opportunities
with cost and administrative burden, especially as RA Program functionality will be
implemented in stages over time.
The IE is charged with the following responsibilities and limitations:
1. Once per year, analyzes operations, accounting/settlement, and design of program and
makes recommendations for changes in a written evaluation report;
2. Does not monitor program Participants;
3. Does not have decision-making authority; and
4. Reports their findings to all RA Program committees.

The day-to-day operation of the program by the NWPP and PO should be separate from the
evaluation of the program by the IE in order to meet FERC’s independence requirements. To
be effective, independent program monitoring and evaluation must be transparent. Every
effort should be made to aggregate data in order to preserve confidentiality, while still
effectively communicating program results to stakeholders.
The IE will be an outside entity (not part of NWPP staff) to be recommended and hired by the
NWPP (with approval from the BOD) but will report to the NWPP BOD.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Other Committees and Structural
Functions

provides the organizational structure for the NWPP. The following sections describe
components of this structure.

Committee of States
The RA Program governance structure will need to include states’ perspectives on matters
such as integrated resource planning, reserve requirements, emerging policies concerning
renewable generation, storage, efficiency and demand resources, and rules for retail choice
(e.g., direct access providers and consumer choice aggregators).
The COS is comprised of state representatives, either from the public utility commission or
state energy office at each state’s discretion. It is envisioned that there would be one
representative from every state from which a Participant hails. The COS would have a Chair
and Co-Chair.
In partnership with the Western Interstate Energy Board, the NWPP RA Program has
commenced a series of meetings and discussion with state representatives to determine the
role and functions of the COS. The goals of this process are:
• Learn and understand Stage 1 inputs/outputs; build trust and understanding.
• Evaluate the COS to determine authority structure for future stages pursuant to a set
timeline.
• Determine whether a role for public power, either through ex-officio/liaison role, or
some other role on the COS is appropriate.
The COS will likely need support from staff; specifics related to staffing support will be further
considered in collaboration with state regulators in upcoming phases.

Program Review Committee
The PRC is a sector representative group charged with receiving, considering, and proposing
design changes to the RA Program. The PRC is the clearing house for all recommended
design changes not specifically identified as time-sensitive or of high RAPC priority (see
below). These recommended changes could come from Participants, the BOD, other
committees, stakeholders, the public, etc.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 40 of 254
Figure 1-3 provides an overview of the PRC review process.
• The PRC will be staffed with facilitation support from the NWPP and program
design/technical support from the PO.
• The PRC will establish a process and criteria for receiving design update
recommendations.
• When recommendations are received, the PRC will work with the PO and NWPP staff
to review recommendations and create proposals for the change; this process will be
defined by the initial PRC once identified.
• As part of the PRC’s proposal process, they will run a public and stakeholder comment
process, also to be established by the first PRC.
• The PRC will also seek input as appropriate from the COS, once their role and authority
is determined.
• The PRC will present all proposals received to the RAPC; PRC will provide RAPC with a
refined proposal, feedback received from the COS and PO, summaries of public
comments received, and their own recommendation (with a minority opinion, if
necessary). If the RAPC rejects a recommendation from the PRC, the PRC may decide
to appeal that decision by taking the proposal to the BOD.
• In the non-binding stage, the PRC will review and add detail to the proposed process
for reviewing and proposing changes. This process will be recommended to the RAPC
for consideration, as will proposed changes to the process in the future.
• The PRC will consist of the following sectors and sector representatives, which could
also be represented by a trade group that serves that sector. Each sector will be
responsible for appointing its representatives:
o RAPC Participants, ensuring appropriate representation among these types of
Participants:
▪ IOUs (4)
▪ COUs (4)
▪ Retail Competition Load Serving Entity (2)
▪ Federal Power Marketing Administration (2)
o Independent power producers/marketers (2)
o Public interest organizations (2)
o Customer advocacy groups (2)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 41 of 254
• It will be important that the PRC is a functional, working committee to avoid design
change bottlenecks. The initial PRC will develop a code of conduct for member
participation. Membership on the PRC will require, at minimum:
o Willingness to represent their sector and work in the best interests of the
regional program;
o Ability and willingness to communicate with their sector to ensure accurate
representation of the sectors’ needs and concerns;
o Consistent attendance and engagement at PRC meetings by the identified PRC
representative; and
o Willingness to collaborate with other PRC members to propose feasible,
reasonable design changes in a timely manner.
• Similarly, to ensure efficient function of the PRC, membership on the committee should
be chosen to provide a diversity of perspectives and expertise within the identified
sector representative categories.
Exigent design changes (e.g., those mandated by FERC order, those with immediate reliability
impacts, those of high priority to the RAPC) may need to utilize an expedited review process.
In these circumstances, the RAPC would work with the PO and NWPP to propose a design
change and would propose that change to the BOD. The PRC, COS, and public would
participate in a comment process directly with the BOD as they review the RAPC’s proposed
response to the time-sensitive design issue. This process is outlined in Figure 1-4.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 42 of 254

Figure 1-3. PRC Review Process
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 43 of 254

Figure 1-4. PRC expedited review process.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 44 of 254
Cost Allocation Principles
Assigning Costs Incurred to RA Program
Any costs will need to be assigned based on the costs incurred in providing contracted
program services, including costs of the BOD, administrative personnel, and shared services
with other NWPP services that are provided outside the RA Program.
When possible, costs associated with specific services or programs (e.g., staff time, program-
specific software, etc.) will be direct assigned.
If direct assignment is not possible where costs support multiple services or programs (e.g.,
cost of BOD, office lease costs, etc.), costs will be allocated using a reasonable cost allocation
methodology.
Allocating Costs to RA Program Participants
Costs assigned to the RA Program will be allocated to Participants on a basis consistent with
the “house and senate” voting described previously. 50% of the costs assigned to the RA
Program will be allocated on a pro-rata basis to Participants. The other 50% of costs will be
allocated based on P50 of each Participant.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 45 of 254

NWPP Resource Adequacy
Program Detailed Design

Forward Showing Design

JUNE 2021

Prepared in collaboration with the Southwest Power Pool, as Program Developer

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 46 of 254
SECTION 2. FORWARD SHOWING DESIGN:
TABLE OF CONTENTS
Forward Showing Program Design ................................................................................................................. 51
Showing and Compliance Timing ...................................................................................................... 52
RA Program Metrics ................................................................................................................................ 55
Program Objective .......................................................................................................................... 55
Planning Reserve Margin .............................................................................................................. 55
Load Forecasting for Forward Showing ........................................................................................... 56
FS Capacity requirement ............................................................................................................... 57
Capacity Critical Hours .................................................................................................................. 57
Regional Interchange Assumptions .......................................................................................... 58
Resource Eligibility and Qualification ............................................................................................... 64
Resource Eligibility .......................................................................................................................... 64
Sale and Purchase Transactions ................................................................................................. 66
Transmission Service Requirements ......................................................................................... 71
Qualified Capacity Contribution of Resources .............................................................................. 72
Storage Hydro .................................................................................................................................. 74
Variable Energy Resources ........................................................................................................... 75
Thermal Resources .......................................................................................................................... 76
Energy Storage ................................................................................................................................. 76
Hybrid Facilities ................................................................................................................................ 78
Customer Resources ....................................................................................................................... 78
Resource Outages ........................................................................................................................... 80
Construction of a Participant’s Forward Showing Portfolio...................................................... 83
Resource QCC ................................................................................................................................... 83
Net Contract QCC ............................................................................................................................ 83
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 47 of 254
Resource Adequacy Transfers ..................................................................................................... 84
Forward Showing Portfolio and Calculation .......................................................................... 84
Deficiency Payment for Noncompliance ......................................................................................... 85
Transmission and Deliverability .......................................................................................................... 86
Showing Exceptions ........................................................................................................................ 88
Load Resource Zones ..................................................................................................................... 89
Modeling Data from the FS Program Provided to the Ops Program ................................... 89
Modeling Process Timelines .............................................................................................................. 91
Section 2: Appendix A - Annual Assessments ............................................................................................. 93
A.1. Planning Reserve Margin ...................................................................................................................... 93
A.1.1. Qualified Capacity Contribution ................................................................................................ 93
A.2. Model Input Update Process ............................................................................................................... 94
A.3. Participant Review and Verification Process of Input Data ...................................................... 95
A.4. Draft Modeling Output Results Sharing .......................................................................................... 95
A.5. Final Modeling Output Results Sharing........................................................................................... 96
Section 2: Appendix B - Modeling Adequacy Standard and PRM ....................................................... 98
B.1. Introduction ............................................................................................................................................... 98
B.2. Software Used ........................................................................................................................................... 98
B.3. Area Modeling .......................................................................................................................................... 98
B.4. Load Modeling .......................................................................................................................................... 99
B.4.1. Load Forecast Uncertainty ........................................................................................................... 99
B.5. Generation Modeling ........................................................................................................................... 100
B.5.1. Thermal Generators ...................................................................................................................... 100
B.5.2 Storage Hydro ................................................................................................................................. 101
B.5.3 Wind, Solar, Run-of-River Resources ...................................................................................... 101
B.5.4 Demand Response Programs .................................................................................................... 102
B.5.5 Behind-the-Meter Generation ................................................................................................... 102
B.5.6. External Capacity Modeling ....................................................................................................... 102
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 48 of 254
B.6. Determination of 1 Event-Day in 10-Year Threshold ................................................................ 103
B.7. PRM Calculation ..................................................................................................................................... 103
B.8. Simulation Process ................................................................................................................................ 104
Section 2: Appendix C - PRM Allocation Methodologies ..................................................................... 105
C.1. Impact of Contingency Reserves on PRM ..................................................................................... 106
Section 2: Appendix D - Qualified Capacity Contribution Modeling ................................................ 108
D.1. Storage Hydro ........................................................................................................................................ 108
D.1.1. Time Period Approach for Summer and Winter Binding Requirements .................. 108
D.2. Areas of Further Exploration .............................................................................................................. 116
D.2.1. 10 Year Period ................................................................................................................................ 116
D.2.2. Interaction with RA Program Modelling .............................................................................. 116
D.2.3. Stress Case Analysis ..................................................................................................................... 116
D.3. Variable Energy Resources ................................................................................................................. 117
D.3.1. Effective Load-Carrying Capability Modeling ..................................................................... 117
D.3.2. Effective Load-Carrying Capability Study Process ............................................................ 118
D.3.3. Determination of ELCC for Future VER Resources ............................................................ 121
D.3.4. Treatment of other classes of VERs in the ELCC analysis ............................................... 121
D.4. Short-Term Storage .............................................................................................................................. 122
D.5. Thermal Units .......................................................................................................................................... 123
D.5.1. Methodology for units that do not have at least 6 years of outage data ............... 125
D.5.2. Methodology for units that do not report NERC GADS (or Equivalent) data ......... 126
Section 2: Appendix E - Transmission Modeling Considerations ...................................................... 127
E.1. Determination of a Transmission Constrained Zone ................................................................. 129
Section 2: Appendix F - Portfolio Construction Details and Examples ............................................ 130
Section 2: Appendix G – Indicative annual assessment results ........................................................... 134
G.1. Disclaimer ................................................................................................................................................. 134
G.2. Planning Reserve Margin .................................................................................................................... 134
G.2.1. Resources Used In Analysis ....................................................................................................... 134
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 49 of 254
G.2.2. Demand values used in analysis .............................................................................................. 136
G.2.3. Loss of Load Expectation Analysis .......................................................................................... 136
G.2.4. PRM calculation ............................................................................................................................. 137
G.3. QCC of Thermal and Storage Hydro Resources ......................................................................... 138
G.3.1. Thermal Resources ....................................................................................................................... 138
G.3.2. Storage Hydro ................................................................................................................................ 139
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 50 of 254
FORWARD SHOWING PROGRAM
DESIGN
The Northwest Power Pool’s (NWPP) Forward Showing (FS) Program is the forward-
looking planning portion of the Resource Adequacy (RA) Program. In the FS Program,
the Program Operator (PO) performs assessments and analyses in accordance with the
FS Program requirements. These assessments and analyses include the Annual
Assessment that determines a planning reserve margin (PRM) and the qualified capacity
contribution (QCC) of Participants’ resources and contracts.
The main component of the FS Program is the FS portfolio submittal and review, in
which Participants provide their data submittals showing that the Participant has met
the FS capacity requirement of the FS Program. When it is determined a Participant is
not compliant with the FS capacity requirements, the PO will apply approved deficiency
payments to the Participant. Table 2-1 presents a summary of key components of the FS
Program.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 51 of 254
Table 2-1. Snapshot of detailed design, additional detail on the FS Program is found in the
materials that follow.
NWPP RA FS Program Snapshot
Program Structure
Bilateral; Participants will continue to be responsible for determining
what resources and products to procure from other Participants or
suppliers.
Compliance
Periods
Two binding seasons: Summer and Winter. Fall and Spring seasons are
advisory (no non-compliance payments).
FS Deadline
FS deadlines will occur seven months in advance of the start of the
binding seasons, with a two-month cure period from notification of any
deficiency by the PO.
PRM
Seasonal PRM will be determined as part of the Annual Assessment for
Summer and Winter seasons and expressed as a percentage of the 1 in
2 peak (P50) load forecast of the Participant.
QCC
Wind and solar resources: effective load-carrying capability (ELCC)
analysis.
Run-of-river hydro: ELCC analysis.
Storage Hydro: NWPP-developed hydro model that considers the past
10 years generation, available water in storage, and current operational
constraints.
Thermal: unforced capacity (UCAP) method.
Energy storage resources (ESR) and hybrid resources: determined by
operational testing until higher penetrations show a need for a
performance-based methodology.
Customer-side resources: operational testing and historical
performance.
Transmission
Deliver showing resources on firm/conditional firm transmission;
demonstrate at FS deadline having procured or contracted for
transmission rights to deliver at least 75% of the FS capacity
requirement from source to load.
Payment for Non-
compliance
Deficiency payment based on cost of new entry (CONE) of a new
peaking gas plant.

Showing and Compliance Timing
The FS Program will be binding for the Summer and Winter seasons. The FS deadline
will be seven months ahead of the start of each binding season (see Table 2-2 and
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 52 of 254
Figure 2-1); at the FS deadline, Participants must demonstrate that they own or have
contracted sufficient QCC to meet their FS capacity requirement, which is based on the
regional metrics as defined by the RA Program and calculated by the PO (e.g., the PRM;
see Section 2.2).
Analysis of 10 years of historical NWPP regional load showed peaks in both Winter and
Summer seasons, necessitating the program observe two binding seasons. This analysis
observed a decline in load and an increase in the availability of capacity for the last half
of September (for the Summer season) and the last half of March (for the Winter
season), enabling the mid-month season delineation.
The Spring and Fall seasons will be advisory; the PO will provide advisory metrics. There
will be no FS deadline or PO review for those seasons, and thus there will be no
deficiency payments for noncompliance for Spring or Fall. However, the PO may
conduct analyses with available data in an advisory manor, and to allow for future advice
to the RA Program and Participants.
Table 2-2. Compliance seasons and deadlines.
Season Binding/Advisory Duration FS Deadline Cure Period
Winter Binding Nov 1– Mar 15 Mar 31 Jun 1-Jul 31
Summer Binding Jun 1– Sep 15 Oct 31
(Of prior year) Jan 1 – Feb 28
Spring Advisory Mar 16 – May 31 N/A N/A
Fall Advisory Sep 16-Oct 31 N/A N/A

After Participants submit their FS portfolio at the FS deadline (i.e., March 31 and October
31), the PO will validate submittals from Participants (e.g., generator test reports, power
purchase and sales agreements, transmission service arrangements). The PO has a 60-
day period following the FS deadline for validation of the submittals. After validation,
the PO will notify Participants of deficiencies; any deficient Participant will have 120 days
from the FS deadline or 60 days from the PO’s notification whichever is later to cure the
deficiency before deficiency payments are assessed.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 53 of 254

FA
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y
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SU
M
M
E
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SP
R
I
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(a
d
v
i
s
o
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)
WI
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Summer Season
Jun 1 – Sep 15
Aug Sept Oct Nov Dec Jan Feb Mar Apr May Jun July Aug Sept
Winter Season
Nov 1 – Mar 15
Spring Season
Mar 16 – May 31
Fall Season
Sept 16 – Oct
31
Cure Period
Jan 1 - Feb 28
Cure Period
Jun 1 - Jul 31
Mar Apr May Jun JulyJanFeb
FS Deadline
Oct 31
Participants must cure any deficiencies by Jul 31
PO validates FS
submittals –
notifies
Participants of
deficiencies by
Dec 31
Participants must cure
any deficiencies by Feb
28
FS Deadline
Mar 31
PO validates FS
submittals –
notifies
Participants of
deficiencies by
May 30

Figure 2-1. Program timeline, including binding (Summer and Winter) and advisory (Spring and Fall) seasons, FS deadlines, and cure
periods.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 54 of 254
RA Program Metrics
Program Objective
The regional RA objective is intended to ensure the RA Program footprint has sufficient
capacity to adequately serve load under a variety of possible scenarios.
The FS Program is designed to identify the capacity needed to meet a loss of load
expectation (LOLE) objective of one event in 10 years where capacity is expected to be
inadequate to meet load plus contingency reserves (CR). An event could be a single
hour or multiple hours in a day; hours of loss of load in a single day, whether
consecutive or inconsecutive, will constitute a single event. Seasonal LOLE objectives of
1-in-10 will be calculated by the PO for Summer and Winter seasons, as defined by the
FS Program.
Planning Reserve Margin
The PRM is obtained through probabilistic LOLE analysis and represents the amount of
dependable capacity needed beyond the P50 load forecast to meet unforeseen periods
of high demand, unexpected resource outages, and other unexpected conditions.
Commonly, the PRM is expressed as a percentage multiplier (e.g., 12%).
The PRM is a key component in determining the necessary amount of qualified capacity
(expressed in megawatts (MW)) needed to meet the demand (load) projections for each
season.4 For the purposes of the FS Program, a hybrid approach consisting of ELCC for
variable energy resources (VERs), UCAP for traditional generators, installed capacity
(ICAP) for ESR and demand response (DR) and a stand-alone methodology for storage
hydro will be employed for modeling the capacity of resources to determine the PRM
(as discussed in Appendix C). The intent of the capacity modeling approach is to
represent resources with respect to their availability. This approach to calculating the
4 The calculation of the PRM includes an embedded assumption of the allocation of CRs but regulating
reserves and other BAA-specific reserves will not be included in the PRM calculation. In accordance with
North America Electric Reliability Corporation (NERC) Standard BAL-002-WECC-2a, BAAs in the western
interconnection are required to carry CRs equal to three percent of hourly integrated load plus three
percent of hourly integrated generation. In the FS capacity requirement, the allocation of CR to each
Participant will require a calculation of each Participant’s position regarding import and export
transactions. Participants with a net import position will necessarily carry a lower capacity requirement
than Participants with a net export position. See Appendix A.1 Planning Reserve Margin for additional
information.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 55 of 254
PRM is known as the UCAP PRM methodology.5 The PRM for the FS Program will be a
UCAP value. The PO will identify the total MW capacity required to meet the 1-in-10
LOLE objective for the RA Program footprint.
The PRM for each season will be determined and expressed as a percentage of the P50
seasonal peak of the aggregated load across the RA Program footprint. The PRM is
equivalent to the aggregate amount of capacity needed within the RA Program
footprint. Individual Participant allocation is determined by multiplying the PRM by their
non-coincident P50 load (individual P50 load forecast). The capacity requirement is met
by Participants showing a commensurate amount of QCC to meet their P50 load
forecast plus the PRM.
The PRM can be represented by the following formula.
𝑷𝑹𝑴 (%)= 𝑸𝑪𝑪 −𝑷𝟓𝟎 𝑳𝒐𝒂𝒅
𝑷𝟓𝟎 𝑳𝒐𝒂𝒅∗𝟏𝟎𝟎

Load Forecasting for Forward
Showing
Load forecasting is a critical aspect of setting metrics appropriately. Participants will
provide the PO their forecasted monthly peaks as well as their historic load data (i.e., 10
years of hourly data, adjusted for curtailed loads, DR, and known incremental energy
efficiency measures not already captured).6 The PO will represent the forecasted
coincident peak (CP) demand of the footprint by modeling each Participant’s historical
load output and aggregating all Participant loads to a regional load shape.

5 Alternative to a UCAP PRM methodology would be the ICAP method, which bases the PRM on the
maximum tested capability of the generation of the Program.
6 Participants will also provide relevant forward-looking data and forecasts for the applicable study horizon
timeframes on either a monthly or seasonal peak basis, supported by evidence, to help inform the PO’s
evaluation of the Participant’s load forecasting methodology. There will be an established process for
Participants to resolve disputes/discrepancies with the PO’s review of load forecast.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 56 of 254
The Participant load forecasts will serve as the basis for P50 load value for each
applicable study horizon and binding season (Table 2-3). The P50 load value that the
Participant is required to provide capacity (and associated PRM) for in each FS season is
monthly peak (of that season) that has the highest P50 load forecast.
Table 2-3. Example P50 load forecast.
Participant provides monthly forecasts for the
Summer season
Month June July August September
P50
Forecast 100 MW 120 MW 130 MW 120 MW
The August load forecast will serve as the P50 value for
the Participant.

Annually, the PO will collect Participant load forecasts and accompanying forecast
methodologies. The PO will review forecasts and methodologies for consistency. At the
outset of the FS Program, the PO will perform a postseason review to compare the
Participant’s peak loads against the loads forecast for that season. The PO will make
recommendations to individual Participants to help improve forecast error and will make
recommendations to the Participant Committee about ways to improve the load
forecasts that improve the overall effectiveness of the Program. At some point, the RA
Participant Committee (RAPC) may recommend to the NWW Board of Directors) that
the PO develop its own load-forecasting function to serve as an independent load
forecast for the purposes of validation; future design work (in 3A) will identify a
triggering threshold for review of the Participant-led load forecasting methodology and
consideration of the PO’s role in this area.
FS Capacity requirement
To derive a Participant’s FS capacity requirement for the season, the maximum of their
forecasted monthly P50 load (of the binding season) is multiplied by 100% plus the PRM
and is calculated using the following equation:
𝑭𝑺 𝑪𝒂𝒑𝒂𝒄𝒊𝒕𝒚 𝑹𝒆𝒒𝒖𝒊𝒓𝒆𝒎𝒆𝒏𝒕=𝒎𝒂𝒙{𝒎𝒐𝒏𝒕𝒉𝒍𝒚 𝑷𝟓𝟎}∗(𝟏𝟎𝟎%+𝒔𝒆𝒂𝒔𝒐𝒏𝒂𝒍 𝑷𝑹𝑴)

Capacity Critical Hours
Key to the FS Program design is the concept of capacity critical hours (CCH). Capacity
critical hours may be different from the peak load hours of the region, as the concept
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 57 of 254
considers other factors that impact when capacity may be in short supply.
Determination of CCH considers the highest capacity need of the RA Program
considering the gross load of the RA Program footprint, the performance of VERs, as
well as the interchange across the footprint to arrive at a net regional capacity need:
𝑵𝒆𝒕 𝑹𝒆𝒈𝒊𝒐𝒏𝒂𝒍 𝑪𝒂𝒑𝒂𝒄𝒊𝒕𝒚 𝑵𝒆𝒆𝒅 (𝑴𝑾)=𝑳𝒐𝒂𝒅−𝑾𝒊𝒏𝒅−𝑺𝒐𝒍𝒂𝒓−𝑹𝒐𝑹+𝑰𝒏𝒕𝒆𝒓𝒄𝒉𝒂𝒏𝒈𝒆

Where:
Load = Participant gross load in MW from 2010-2020
Wind = 2020 installed wind resource output in MW synthesized back to 2010
Solar = 2020 installed solar resource output in MW synthesized back to 2010
Run-of-River = 2020 installed run-of-river resource output in MW synthesized back
to 2010
Interchange = modified interchange in MW for 2010-2020 as calculated in Section
2.3.3.

Capacity critical hours are those hours where the net regional capacity need is above the
95th percentile (highest capacity need hours).
Distinguishing the CCH from peak load hours is important because there may be peak
load hours where the resource capacity in the RA Program footprint will have more
availability than in other hours. For example, while there may be instances of high loads
during the month of June, there is also usually an abundance of run-of-river hydro
generation. Since the output from run-of-river hydro must be used at that time, this
could result in periods of excess capacity even though loads are generally high. As the
NWPP footprint continues to see an increase of wind and solar resources, this potential
capacity condition will become more applicable to those resources as well.
The following FS Program concepts rely on the CCH:
• NWPP Storage Hydro QCC Methodology determination (see Section 2.5.1)
• Thermal Resource QCC determination (see Section 2.5.3).

Regional Interchange Assumptions
In setting the PRM and identifying CCH, it is important to understand how much of the
capacity residing within the RA Program footprint will be available to Participants under
stressed grid conditions. While Participants of the RA Program are located within a
defined footprint, the broader Western region remains an interconnected system and
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 58 of 254
regional interchange (e.g., imports and exports) should be expected during all seasons.
Due to the bilateral nature of the existing market, the PO will need to make data-driven
assumptions regarding the magnitude of imports and exports to appropriately set the
PRMs; this is especially true in initial seasons in order to arrive at metrics and program
rules which will compel Participants to provide additional insight into planned firm
interchange. The PO intends to include the results from this analysis as an input into the
LOLE/PRM assessments to set an appropriate PRM for the initial start of the Program
and will re-evaluate as the Program obtains more operating experience .
A review of the regional interchange data from 2010-2020 showed regional interchange
has changed drastically in the past three years: from near constant flat NWPP export
level (in the 3,000-5,000 MW range, see Figure 2-2) to a shape that shows exports in late
evening and early morning hours (in the 3,000-5,000 MW level) with declining exports in
the daytime hours (Figure 2-3). This new regional interchange shape appears to closely
follow the timeframes of solar output in California.

Figure 2-2. Raw regional interchange from the NWPP footprint 2010-2017 – a relatively
flat/consistent interchange profile for both seasons where positive values represent exports from
the NWPP footprint..

0
500
1000
1500
2000
2500
3000
3500
4000
4500
5000
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
MW
h
Hour Ending
Winter Summer
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 59 of 254

Figure 2-3. Raw regional Interchange 2018-2020 - declining daytime exports and peaks in
morning and evenings. Roughly follows California solar production.

Assuming the recent interchange shape is most representative of future patterns, a
methodology was established to adapt the previous seven-year period (2010-2017) to
be more reflective of future resource mix assumptions driving recent interchange
patterns (high solar resource penetration in California that results in a reduction of
NWPP exports during the day, followed by high NWPP exports in the off-solar hours).
The objective of applying this methodology was to establish a realistic dataset for use in
determining CCH (Section 2.3.2).
It was assumed that hour ending 19 (HE19) interchange should remain unchanged from
its historical value throughout the 10-year period. This assumption accounts for the lack
of solar at this hour and sets a basis for further calculations for other hours. Next, the
interchange for all hours (HE1-HE24) for years 2018-2020 was averaged on an hourly
basis (see Figure 2-4). The average interchange in hour HE19 was compared to all other
hours of the hourly average interchange shape created in the previous step. The
difference of the averages (e.g., HE19 compared to each individual hour, see green
arrows on Figure 2-4) of these interchange values from the 2018-2020 calendar years
was then applied to the hourly interchange of all years in the 10-year period (2010-
2020). This resulted in a new hourly interchange shape for the entire 10-year period
closely resembling interchange shape for 2018-2020 but retaining interchange
amplitudes (for HE19) of the original data sets.
-500
0
500
1000
1500
2000
2500
3000
3500
4000
4500
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
MW
h
Hour Ending
Winter Summer
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 60 of 254

Figure 2-4. 2018-2020 hourly average loads were analyzed to determine appropriate offsets to
apply to 2010-2017 load shapes. The green arrows show how hourly average loads were
compared against the HE19 average load (presumed to remain unchanged, due to lack of solar
in this hour) to identify an appropriate offset for each hour. Each hour’s offset was applied to the
corresponding hour average in the 2010-2017 data set to arrive at an adjusted hourly load
profile accounting for the changed resource mix.

Further modifications to the load shape were made to account for market conditions
that resulted in high export periods where the capacity that was exported may have
otherwise been able to have been used for the benefit of the RA Program footprint (had
the program existed at the time). For example, if exports occurred during periods of
excess capacity (e.g., high run-of-river output) within the RA Program footprint, and the
energy price outside of the RA Program footprint was at typical market (or below
market) prices, the capacity may not have been exported if the footprint were to have a
need for the capacity, as future conditions anticipate.
The following categories were created to evaluate these exports:
Economic sales: made possible by excess generation in RA Program footprint, it
was assumed this capacity would have been available for the RA Program
footprint, had it been needed.
Scarcity sales: in times of high market prices in areas outside of the RA Program
footprint, it was assumed that historical exports made during those time periods
would not have been available if required by RA Participants.
0
500
1000
1500
2000
2500
3000
3500
4000
4500
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
MW
h
Hour Ending
Avg Interchange Summer 2018-2020
HE19
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 61 of 254
In order to separate exports into the above two categories, energy market conditions
were analyzed, and criteria developed to determine whether exports may be economic
sales or scarcity sales. The criteria are as follows:
• The market-clearing heat rate (e.g., price of power divided by price of natural gas)
for California was used as a proxy for external demand:
o For conditions when the heat rate is less than 10mmBTU/MWh, exports
from NWPP were determined available to NWPP; export interchange was
reduced to zero (imports were unchanged). This low level of heat rate
indicates that market prices were not reflecting scarcity events and the
exports were economic.
o For conditions when the heat rate is greater than 15mmBTU/MWh, exports
from NWPP were considered to be scarcity sales so these values remained
in interchange and were not used as a load modifier (imports were also
unchanged). This higher heat rate is reflective of traditional peaking units,
which are commonly operated and exported under scarcity conditions.
o For conditions when the heat rate was greater than 10 but less than 15,
exports were linearly reduced from their values at 15 to zero.
Starting in 2013, a carbon adjustment of $6/MWh was applied to California market price
before determining the market clearing heat rate.
For import transactions, it was assumed that these imports would continue to be
brought into the RA Program footprint regardless of market conditions. The results of
this modification of the load shape resulted in the load shapes in Figure 2-5.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 62 of 254

Figure 2-5. 2010-2020 interchange adjusted by CA heat rate analysis. Hourly average
interchange was modified to account for economic and scarcity sales. Scarcity sales (high
market-clearing heat rate) were presumed to be unavailable to the RA footprint and were
unchanged, while capacity sold in economic sales was presumed to be available to the RA
footprint if necessary. These hourly averages also include adjustments for resource mix changes,
as described in Section 2.3.3.

Other Items of Consideration for Regional Interchange
The interchange values reviewed are based on actual historical interchange. The
interchange includes both firm and non-firm transactions. Special care must be taken by
the PO to ensure that certain transactions are not “double-counted.“ For example, if a
transaction is included in a Participant’s FS portfolio, it will not be included (again) in the
determination of interchange transactions to/from the RA Program footprint for the
studies that determine the PRM.
Future Changes for Treatment of Interchange
It is understood that conditions have changed in the most recent 10 years, and it is
possible that they will continue to change going forward. A review of the methodology
for adjusting load based on interchange assumptions will be repeated annually to assess
appropriateness as well as the results of the current methodology to determine latest
trends. If most recent year(s) shows a significant differing trend from the presented
-2500
-2000
-1500
-1000
-500
0
500
1000
1500
2000
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
MW
h
Hour Ending
Summer (adjusted)Winter (adjusted)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 63 of 254
methodology, changes to the methodology will be discussed and adjustment sought
with RAPC for adoption, as necessary.
Resource Eligibility and
Qualification
Participant resources and non-Participant resources (under contract) are capable of
providing capacity necessary to meet a Participant’s FS capacity requirement. In order to
receive a QCC for these resources, a Participant must provide necessary information and
data to the PO. The PO will develop and maintain a registration and certification process
for all resources identified for the FS Program.
Resource Eligibility
All generation resources owned (or jointly owned) and/or operated by a Participant and
any resources (e.g., contracts or demand-side resources) claimed by a Participant on its
FS portfolio will be required to register with the PO in order to receive a QCC value.
There may be exceptions allowed as discussed later in this section.
Generation from resources owned/operated by non-Participants will also be encouraged
to register with the PO in order for Participants to claim capacity from these resources
toward their FS capacity requirements – see the following sections for additional detail
on registration by sellers and/or purchasers. Certain allowances will be made for
contracts that are considered “grandfathered” – those agreements with an effective date
before the effective date of the RA Program (or a date otherwise agreed to). Although
allowances may be granted, limitations will be placed on these units and associated
contracts. Participants will need to provide the PO the information listed in Table 2-4, at
a minimum.
The proposed minimum resource size for recognition by the RA Program is 1 MW. Load
Responsible Entities (LREs) with responsibility for individual resources of less than 1 MW
could aggregate them to meet this requirement.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 64 of 254
Table 2-4. Registration and certification information.
The registration and certification process for all resources will require, but will not
be limited to, the following items:
Resource information Owner, operator, technology, and fuel type
Name Facility common name
Location
Balancing Authority Area (BAA) and physical
location information related to zone determination
(applicable for transmission, ELCC, and thermal QCC
analysis)
Maximum capacity (nameplate) Summer and Winter values
Demonstration of operational and
capability testing
Historical performance showing Real Power output
will meet the operational test requirements for
existing resources operational data from within the
two years prior to the FS date is acceptable for the
verification of Real Power

Capability testing – Either the RA Program can
develop its own testing requirements, or existing
testing requirements may be adopted. Testing
should, at a minimum, meet the requirements of
North America Electric Reliability Corporation
(NERC) MOD-025

Outage Data
NERC Generator Availability Data System (GADS)
data (or equivalent) for thermal and storage hydro
resources will be incorporated into the
determination of QCC. Outages will not be
necessary for wind, solar, or run-of-river, as the
ELCC methodology already considers that
information.
Historical Output
Historical output shapes (hourly) to be provided for
wind, solar and run-of-river resources. For storage
hydro resources, historical output shapes along with
other data required by the NWPP Storage Hydro
QCC Workbook.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 65 of 254
Sale and Purchase Transactions
To be counted toward meeting a Participant’s FS capacity requirement, power supply
contracts will need to include certain provisions. The different contractual products
envisioned to meet these requirements are discussed below, and generally fall into two
categories: energy (plus RA capacity) contracts and capacity contracts. There are also
considerations made for existing contracts (grandfathering).
Generally, requirements for eligible contracts include (additional detail to follow):
• Identified source (e.g., resource or system must be specified);
• Exclusive rights to the capacity claimed - assurance this capacity is not being
relied upon for another entities’ RA and will not be cut prior to emergency load
shedding procedures; and
• Firm, conditional firm, or secondary network transmission from the resource to
the load (as further detailed in Section 2.4.3).
Purchase and sale transactions that meet FS Program requirements (either from within
or from outside the RA Program footprint) will be submitted by each Participant. The
amount of the transaction will be reflected as an RA capacity resource for the buyer and
an RA capacity obligation for the seller, so long as the requirements in the following
sections are met.
Firm capacity sales to parties outside the RA Program footprint must be declared and
included as a capacity obligation on the Participant’s FS portfolio. Non-firm capacity
exports will not be deducted (from a Participant’s FS portfolio) but must be curtailable in
the operational timeframe.
2.4.2.1. Energy (plus RA capacity) Contracts
In order to be eligible for inclusion in a Participant’s FS portfolio, energy contracts must
include both firm energy and capacity. These energy contracts are envisioned to be
similar to existing WSPP Schedule B (resource-specific sale) and Schedule C
(system/fleet sale) contracts, though additional requirements must be met in order to be
eligible.
These requirements can be satisfied with an exhibit or an attachment that contains
provisions to qualify for consideration in the FS portfolio review; expectations for
demonstration of meeting these requirements is discussed in the following sections.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 66 of 254
Resource-Specific Contracts
Resource-specific (Schedule B-type) energy contracts can be executed between
Participants or with external parties. In either case, to be counted the resource(s) that is
the subject of the agreement must be registered with the PO, and the PO will calculate
the resource’s QCC.
If both buyer and seller are Participants, the seller will already have registered their fleet
of resources with the PO; the resource(s) in question will have an established QCC. The
purchasing Participant will claim the QCC in their FS portfolio and the selling Participant
will debit the QCC value from their FS portfolio.
If the seller is a non-Participant, the resource(s) that is the subject of the agreement shall
be registered by the owner with the PO. If the resource in question has not been
registered by the owner, depending on circumstances, additional options are available
to buyer Participants:
• If the Participant has adequate data to register the resource for the owner, the
Participant will collect the data and submit to the PO. The PO will then determine
the QCC of the resource. The QCC of the resource will be claimed by the
Participant in their FS portfolio.
• If the Participant does not have adequate data to register the resource for the
owner, and the agreement is considered to be grandfathered, then the
Participant will be able to claim a discounted average QCC value for the resource
type in their portfolio. In this case, the Participant is not required to submit a
waiver request.7It is important to note that resource-specific contracts may have
a stated MW value that differs from their determined QCC value. For example, a
resource-specific sale from a 100 MW gas peaking facility may have a QCC of 90
MW. The QCC is used exclusively for the purposes of the FS Program and is not
necessarily equal to the contracted capacity.
System Sales
For energy contracts that are system sales (Schedule C-type) between Participants
(buyer and seller are both Participants), the system/fleet that is the subject of the
agreement will be registered with the PO8. The PO will have previously determined the
cumulative QCC of the system in question. Once verified, the purchaser (Participant
7 At this time, the amount of the discount and the allowable threshold (percentage of portfolio allowed to
contain this discounted type of resources) has not been determined.
8 Participants will register each resource within their system/fleet, not a single registration value
representing their aggregated system/fleet.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 67 of 254
claiming capacity) will claim the full capacity of the contract in their FS portfolio and the
seller will decrement the full capacity of the contract from their FS portfolio. If the
contract is a slice-of-system type contract, the capacity value of the contract will
generally be determined by multiplying the seller’s Resource QCC value by the
percentage share of the purchaser. Some slice-of-system contracts may not be for a
seller’s entire resource portfolio, in which case the percentage may be taken from some
other aggregation of owned resource QCCs.
The PO will not have knowledge of specific contractual requirements regarding the
assignment of damages or deficiency payments for the FS or Ops Program, nor will the
PO be a party to the commercial agreement between buyer and seller.
For energy and capacity contracts that are system transactions (Schedule C-type) in
which the seller is a non-Participant, the system/fleet capacity that is the subject of the
agreement shall need to be deemed surplus to the seller’s estimated needs and must be
subject to full replacement of the capacity at the seller’s cost; this replacement cannot
be resolved with liquidated damage provisions. This demonstration will be accomplished
through an attestation by the seller. The attestation should include specifications as to
what the seller deems to be “surplus” capacity, such as:
• The transaction is supported by physical generation capacity that is surplus to the
expected capacity requirements/obligation of the seller;
• The seller is not relying on the future procurement of capacity in short-term
markets to support the delivery;
• The contracted product will be backed by any required operating reserves; and
• The transaction will meet the transmission requirements of the FS Program.

Once verified, the purchaser (Participant claiming capacity) will claim the full capacity
value of the contract in their portfolio. In the Ops Program, firm block system sales will
not be subject to variations in performance. Slice-of-system type contracts will
experience over and under performance as compared to their assessed QCC capacity
value; treatment of these variations in performance will be assessed on a contract-by-
contract basis. Similar to resource-specific contracts, the PO will not have knowledge of
specific contractual requirements regarding the assignment of damages or deficiency
payments for the FS or Ops Programs, nor will the PO be a party to the commercial
agreement between buyer and seller. The purchaser (Participant claiming capacity) will
have the performance responsibility in the Ops Program and will be responsible for
contracting in accordance with its business practices and requirements.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 68 of 254
Grandfathered Agreements
Participants may have long-standing agreements that precede the life of the RA
Program. The RA Program is expected to honor these “grandfathered agreements” to
the extent possible. These contracts may be either resource-specific or system based
and may be executed with Participants or non-Participants. Participants are encouraged
to pursue the above registration and verification process for their existing processes
(registration and/or attestation), rather than a grandfathering exemption.
There are some grandfathered agreements in existence in which a source/resource is
not identified in the agreement. For these agreements, it must be possible for the PO to
presume a source or sources (potentially with the assistance of the agreement parties)
for the contract.
• If the source can be presumed by the PO to be a resource(s) or system(s) already
registered with the Program, the selling Participant will debit their system in their
FS portfolio and the buyer will claim full capacity value of the contract on their FS
portfolio.
• If it is determined that the source(s) are non-Participant owned resources, the
Participant will work with the PO to determine the appropriate capacity value of
the contract and the Participant will seek an attestation (as described in Section
2.4.2.1). The Participant will be able to claim the accepted value on their FS
portfolio and retains the operational performance obligation.
If the Participant has an agreement with a non-Participant that is considered a
“grandfathered agreement,” a source is identified or can be presumed, and an
attestation cannot be obtained, the Participant will work with the PO to determine the
appropriate capacity value of the contract, which will then be allowed to be claimed on
the Participant’s FS portfolio. At this time, a maximum threshold for such a contract
arrangement type (grandfathered without registration or attestation) has not been
determined.
If the PO cannot determine a presumed source for such grandfathered contracts, the
Participant cannot claim any capacity from the contract on their FS portfolio9. No new
contracts (after the effective date of the RA Program or other date agreed to by the RA
Program) of this type will be accepted for FS Program use. Renewals of any
9 The PO will employ discretion upon review of contracts that may include sufficient information to
determine a source (e.g., references to generation from a certain BAA).
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 69 of 254
grandfathered agreements after the commencement of the RA Program will require
review and approval of the PO.
Non-Performance of External Resources
Resources that are owned by non-Participants and exhibit poor performance during the
Ops Program will be subject to having their QCC value re-evaluated by the PO in
accordance with program expectations in subsequent seasons. Poor performance will be
at the judgment of the PO and will include factors such as persistent unexcused delivery
failures.
2.4.2.2. Capacity Contracts
For capacity contracts, the purchaser has rights to capacity, but energy is only delivered
under specific circumstances allowed in the contract. Like energy contracts, capacity
contracts must meet the general contract requirements listed at the beginning of
Section 2.4.2.
Traditional Capacity Contracts
Capacity contracts must have clear provisions that demonstrate how the purchaser is
able to call on the capacity during applicable binding seasons. The determination of
QCC for contracts that come from resources (fleet or resource specific) inside or outside
the RA Program footprint will follow the same rules as applied for energy and capacity
contracts in Section 2.4.2.1.
Transfer of FS Capacity Requirement
In an “RA Transfer Agreement,” a new type of contract being developed for use in the
RA Program, the selling Participant takes on some of the FS capacity requirement of the
purchasing Participant. This type of contract can only be executed between two RA
Program Participants. The transmission service arrangements must be included in the
agreement (determined by contract as to whether the purchaser or the seller provides).
The subject capacity of these agreements is represented as a decrement to the
purchaser’s FS capacity requirement and as an addition to the seller’s FS capacity
requirement. Table 2-5 provides an example.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 70 of 254
Table 2-5. FS capacity requirement transfer contract.
Participant ”A” contracts with Participant ”B” to purchase 100
MW of FS capacity requirement transfer
Pr
i
o
r

t
o

t
h
e

tr
a
n
s
f
e
r
Participant ”A” FS capacity requirement is P50 + PRM = 3000
MW + 450 MW (15% PRM) = 3,450 MW
Participant ”B” FS capacity requirement is P50 + PRM = 4,000
MW + 600 MW = 4,600 MW
Af
t
e
r

t
h
e

tr
a
n
s
f
e
r
Participant ”A” FS capacity requirement is now 3,450 MW –
100 MW = 3,350 MW
Participant ”B” FS capacity requirement is now 4,600 MW +
100 MW = 4,700 MW

In addition to transferring all or a portion of the FS capacity requirement from the
purchaser to the seller, the capacity specified in the RA Transfer Agreement is subject to
be called upon by the PO to address the purchaser’s Ops Program capacity deficit
(resulting from load, VER over/under performance or uncertainty), if any, prior to having
capacity and/or energy provided to the purchaser by other Participants in the Ops
Program. See Section 3.4.4 for additional details on how RA Transfers are deployed in
the Ops Program.
Transmission Service Requirements
While designing the RA Program, the Steering Committee considered the following
objectives and constraints:
• Encourage procurement of firm transmission service sufficient to demonstrate
deliverability of resources to load, while recognizing the need for flexibility where
necessary or appropriate.
• Enhance overall visibility with respect to deliverability (from generator to load) for
resources used for program compliance, supporting situational awareness and
regional planning.
• Support and enhance reliability across the region without supplanting existing
responsibilities of Balancing Authorities, LREs/Load Serving Entities (LSEs),
Transmission Service Providers (TSPs), and others.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 71 of 254
• Rely on existing Open Access Transmission Tariff (OATT) frameworks to facilitate
transmission-related requirements for demonstration of RA and sharing of
diversity across the RA Program footprint.
• Respect program Participants’ OATT rights and responsibilities and Participants’
other legal obligations, including contractual commitments and statutory
requirements.
• Design the Program in a manner that achieves deliverability objectives in a
manner that is consistent with continued market efficiency in the operational
time horizon.
Additional work will be undertaken in Phase 3A to further consider an identified gap in
RA related to third party LSEs that either a) do not participate in the program or b)
economically displace their RA resources with other resources (including on non-firm
transmission products) and do not make available their RA resources for dispatch
(resulting in use of NERC schedule 4 or 9 to fill the gap).
Qualified Capacity Contribution of
Resources
Qualified capacity contributions (QCC) will be determined for all resources contributing
to a Participant's FS portfolio. The QCC of a resource will represent the amount of MW
of ”accredited” capacity determined to be reliably available from the resource. The QCC
of a Participant’s system will be the sum of all QCCs for each resource (contracted and
owned) in their fleet. The QCC calculations will be updated by the PO on an annual
basis. The methodology for assessing resources will effectively reflect a resource type’s
capacity contribution during the region’s CCHs. Table 2-6 presents a summary of QCC
methodologies.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 72 of 254
Table 2-6. Resource types and QCC methodologies.
Resource QCC Methodology Notes
Storage
Hydro
Time-period approach to
estimating capacity contribution
in a manner that objectively
reflects operational restrictions
and targets of hydro resources,
and the associated
considerations that go into the
dispatch decision-making
processes.
QCC values will be calculated for
each month.
See Appendix D, Section D.1 for
NWPP Storage Hydro QCC
Methodology.
The RA Program footprint is unique due to the
abundance of hydro generation, no existing RA
Program has employed an approach to
qualifying capacity that would be appropriate.
The NWPP Storage Hydro QCC Methodology
includes a range of hydrological conditions and
is verifiable by the PO. It assesses output during
CCHs, as well as ICAP and usable energy in
storage, to determine how much capacity
should be available during CCHs in the future.
The storage hydro capacity contribution
evaluation will use the historical CCH identified
RA metrics analysis (PRM, LOLE, load
forecasting, etc.), as described in Section 2.3.2.
VERs
Capacity based on ELCC analysis
of historical data (minimum of
three years historical data, as
available); ELCC will be evaluated
by month and by zone.
Zones will be climate/fuel supply-based (versus
transmission-based); these zones will need to
be defined in Phase 3A.

Run-of-River
Hydro10
Capacity based on ELCC analysis
of historical data (Steering
Committee proposes minimum
of three years historical data, as
available); ELCC will be evaluated
by month and by zone.
Run-of-river is less than one hour of storage,
not in coordination with another project.
Zones will be climate/fuel supply-based (versus
transmission-based) and will be defined in 3A.
Thermal
resources UCAP approach for all hours. Using six years of historical data11 (removing
the worst performing year) for each season.
Short-term
Storage
ICAP Testing – ability of the
resource to maintain the value
over the specified duration
represents its capacity value.

10 Methodology is based on data that reflects the actual operation of the facilities during past high load
periods and reflects the complexities that went into the operation of the resources during those periods.
11 North America Electric Reliability Corporation GADS or similar with a validation process – accommodating
Canadian/Federal entities not using NERC GADS
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 73 of 254
Resource QCC Methodology Notes
Hybrid
Resources
“Sum of parts” method
ESR will use ICAP Testing.
Generator will use appropriate
method as outlined above.
For example, an ESR paired with a wind facility
would use ICAP Testing for the ESR and ELCC
for the wind facility.
Customer
Resources
Customer resources can either
register as a load modifier or as a
capacity resource.
Load modifier – needs to be controllable and
dispatchable, should demonstrate control of
program and meet testing criteria or
demonstrate load reduction for periods of up
five continuous hours.
Capacity Resource – need to meet testing
criteria and demonstrate load reduction for
periods of up to five continuous hours.
Customer resources (Behind-the-meter
resources) can be aggregated to the 1 MW
requirement to be considered a capacity
resource, granted that they are in the same
BAA, controllable and dispatchable, and visible
to the Ops Program.

The PO will monitor to determine if the above methodology is accurately capturing the
contributions of each resource type at larger scale. Modifications in the future may be
necessary, and the PO will work within the RA Program definitions, rules, and
governance processes to raise any proposals.
Storage Hydro
Due to the significant amount of storage hydro12 resources in the RA Program footprint
and the complexity of operations across the region, and from project to project, a
specific storage hydro methodology for QCC treatment was developed for the FS
Program (NWPP Storage Hydro QCC Methodology).
The methodology presents a “capacity view” that maximizes output during CCH for each
calendar day while considering water limitations and the unique limitations/operations
of each project. The NWPP Storage Hydro QCC Methodology is used by Participants to
12 Storage hydro resources are defined as hydro resources with the capability to store at least one hour
worth of water.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 74 of 254
calculate the QCC of their storage hydro resources through the use of the Storage
Hydro QCC Workbook.
The methodology considers each resource’s actual generation output, residual
generating capability, water in storage, reservoir levels (if applicable), and flow or project
constraints over the previous 10-year historical period. The methodology then
determines the QCC of the storage hydro project by assessing the historical actual
generation occurring during the CCH on any given day and the ability to increase
generation during CCHs on the same calendar day, subject to useable water (energy) in
storage, inflows/outflows, and expected project operating parameters/constraints and
limitations. The impact of forced outage rates, based on historical NERC GADS (or
equivalent) information, as well as planned outages are also incorporated into the
storage hydro. The resulting QCC is determined as the average contribution to the top
5% of CCH for each Winter and Summer season over the previous 10 years. See
Appendix D, Section D.1 for more details.
Variable Energy Resources
The FS Program considers wind, solar, and run-of-river resources to be VERs; VERs will
have their QCC determined using a version of ELCC methodology. In advance of each FS
deadline, an ELCC analysis will be performed to determine the QCC for each month of
the Winter and Summer seasons. A QCC will be assigned to all VERs on a zonal basis in
the RA Program footprint.
The PO will require at least three years of hourly historical output data from the resource
to calculate the QCC of VERs. For facilities with known and measurable curtailments,
curtailed energy will be added back for purposes of having the resource studied in the
ELCC analysis.
New resources or resources in service less than three years will be able to use data from
nearby facilities (or facilities within the same zone until they have been in operation for
three years). Alternatively, the Participant will have the ability to provide forecast data
based on historical meteorological information. For repowered facilities, a Participant
may use forecast data based on a facility’s previous operations data adjusted for the
repowered specifications.
A detailed description of the ELCC methodology and analysis can be found in Appendix
D, Section D.3.1.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 75 of 254
Thermal Resources
For resources that use conventional thermal fuels such as coal, gas, biofuel and nuclear,
the FS Program will use a UCAP methodology13 to determine QCC.
The UCAP methodology will use a season equivalent forced outage factor (EFOF)
calculation in line with the NERC GADS. The top 5% of CCHs will be used to determine
the hours to be used in calculating the EFOF for each unit. The EFOF calculation will be
performed for each year of the historical look-back period. Participants will be required
to provide the PO with NERC GADS (or equivalent) outage data for the previous six
years. The PO will calculate the equivalent outage rate by removing the year with the
lowest EFOF (for each Summer and Winter seasons) and then taking an average of the
remaining five years of data. The final calculated EFOF will be assigned as the UCAP
amount for the thermal generator for the entire binding season.
Planned outages are not included in UCAP calculations. Planned outages are considered
during the FS portfolio review (i.e., units on planned outages are not included as
showing resources during the applicable season). This means planned outages should
be planned in advance of the FS deadline.
Due to the possibility of certain high impact outages affecting multiple calendar years,
which would hamper the effectiveness of the practice of removing the worst performing
year, Participants will have the option to request an exception for certain high impact
outages to not contribute towards the calculation of the EFOF. The PO will establish a
process and criteria for requesting exceptions and determine the validity of an exception
request. The PO’s decision may be appealed in accordance with general RA Program
dispute resolution procedures.
For units new to the FS Program, the PO may use class average data for units of similar
size, age, and technology type. For such units, operating performance data will replace
the class average data as operating history is accumulated while the class average data
is used to complete the data for the remaining time requirement.
Further information about the thermal QCC analysis can be found in Appendix C.
Energy Storage
Energy storage resources such as pumped storage facilities or battery storage systems
have a limited amount of storage capability compared to most storage hydro resources
13 Most RA Programs use an ICAP or UCAP to determine the QCC of thermal resources. The ICAP
methodology is generally a temperature-adjusted test against the nameplate capacity of a resource. The
UCAP methodology adjusts a resource’s ICAP value to account for forced outages.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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in the RA Program footprint. The methods used by other RA Programs include the
following:
• Installed Capacity Testing – ICAP testing methodology relies on the ability of the
ESR to perform for a specified duration. The ability of the resource to maintain
the value over the specified duration represents its capacity value. This
methodology is simple to apply and has been shown in other areas to have
accuracy for lower penetrations of ESRs.
• Effective Load-Carrying Capability – ELCC methodology is performed similar to
ELCC methodology for VERs. Information on the ESRs’ storage capability is
required to determine its ELCC value. While ELCC may provide an accurate value
of the capacity such resources provide (even in larger penetrations on a system),
the methodology can be complex and administratively burdensome.
• Performance-Based – performance-based methodologies rely on the tracking of
historical performance of ESRs during times of system capacity need. This
methodology has components similar to the NWPP Storage Hydro QCC
Methodology.
With the low penetration of pumped storage and battery storage ESRs located in the RA
Program footprint at this time, it was determined that the best method for capacity
value calculation is the ICAP Testing methodology. The top 5% of CCHs was analyzed to
aid in the determination of the duration requirement necessary for the ICAP Testing
methodology specifically for battery storage systems. This analysis provided the
following results:
• 61% of Summer days contained a total of 4 or fewer CCH.
o The weighted average CCH per day for the Summer season was 5 hours.
• 74% of Winter days contained a total of 4 or fewer CCH.
o The weighted average CCH per day for the Winter season was 4.7 hours.

The FS Program will use a five-hour duration requirement for the ICAP Testing
methodology to determine battery system ESR QCC. Table 2-7 contains example QCCs
associated with different duration ESRs.
Table 2-7. Example QCC determination for battery storage.
MW
(maximum output) Duration Weighting QCC
100 MW 2 hours 2/5 = 40% 100 MW * 40% = 40 MW
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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100 MW 4 hours 4/5 = 80% 100 MW * 80% = 80 MW

Further information about the short term QCC analysis can be found in Appendix D,
Section D.4.

Hybrid Facilities
Hybrid facilities are resources that have at least two different resource types at a
common location where one of those resources is an ESR. A common practice that has
been observed among hybrid resources is oversizing generating capacity compared to
the size of the interconnection service as studied and provided by the TSP. An example
would be a generating resource that has a Generator Interconnection Agreement for
200 MW but consists of a 100 MW ESR resource coupled with a 150 MW solar resource.
The FS Program will follow a similar methodology as for short-term ESRs and use an
ICAP Testing methodology for the ESR portion of the hybrid facility. When the ESR is
coupled with a VER resource, the remaining capacity is determined by the ELCC
methodology used for VERs. This approach to hybrid resources is referred to as the
“Sum of the Parts” methodology. Under this methodology, the PO will implement a limit
to prevent the QCC from exceeding the amount of interconnection service obtained by
the Participant and will request such information from the Participant.
Customer Resources
Resources that are generally located on the customer side of the meter can be included
in the FS Program. These customer resources are commonly captured through DR
programs and behind-the-meter generation or energy storage. Energy efficiency
programs may also fit into this category. Customer resources are generally identified as
a demand side resource or a behind-the-meter resource, which in order to be eligible
for capacity credit in the FS must: 1) be controllable and dispatchable by the Participant
and/or host transmission operator, and 2) not already be used as a load modified in the
Participant’s load forecast (i.e., serving a portion or all of the load not included in load
forecast). As a general concept in addressing customer resources, capacity impacts from
resources that are typically spread across a Participant’s system (across its retail
customer base), are non-controllable and non-dispatchable will be expected to be
accounted for in the Participant’s annual load forecasts that are provided to the PO.
Examples of these resources include disaggregated rooftop solar installations and some
types of energy efficiency programs.
There are two potential methods of accounting for the RA impacts of customer
resources that are controllable and dispatchable:
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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• Load modifier - A load modifier is considered a reduction of the Participant’s
forecasted net peak demand (reduction in load). Planning reserves are not
required for resources that are considered load modifiers. Demand response
programs that register as a load modifier will need to be controllable and
dispatchable and should be able to demonstrate such control and meet testing
criteria for load reduction for periods of up 5 continuous hours. Demand
response programs that register as a load modifier will be listed as a separate line
item in a Participant’s FS submittal and will be subtracted directly from the
Participant’s P50 load responsibility14.
• Capacity resource – A capacity resource is a resource that is considered to serve
the Participant’s load and can be separately identified or metered. Capacity
resources are subject to being backed up by planning reserves (e.g., a 10 MW
resource would need 1.5 MW of planning reserves if PRM is 15%). However, if a
DR program is registered by a Participant as a capacity resource because of its
controllability and composed strictly of shedding load, then the DR program may
qualify as a capacity resource that does not have to be backed up by planning
reserves. DR programs that register as capacity resources will need to meet
testing criteria and demonstrate load reduction for periods of up to 5 continuous
hours.
Table 2-8 gives examples of various types of customer resources and how they may be
classified as load modifiers and capacity resources. .
Table 2-8. Examples of customer resource types and recommended default treatment by the
program; not a comprehensive list, and treatment by the program will be assessed during the
registration process.
Resource Example Default Treatment
Traditional rooftop solar installations or
unmetered generation Load modifier
Energy efficiency Load modifier
Time of use/Voluntary load
conservation Load modifier
14 DR programs that are not controllable or dispatchable are included in and are submitted with the
Participant’s load forecast.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Resource Example Default Treatment
Residential demand response (e.g.,
thermostat or HVAC) Load modifier
Large customer demand response
(e.g., tariff programs) Either
Automated demand response Either
Customer on-site generation or
distribution resource (separately
metered)
Either

Demand response programs that are restricted to or used solely for CRs will need to be
able to be deployed for no less than a full hour starting at the beginning of the hour
(xx:00) although actual conditions may necessitate multiple hour deployments. Demand
response programs serving to replace CRs do not need to meet the requirements of the
FS Program and will be governed by the NERC standard regarding CRs. Demand
response programs serving to replace CRs will serve only to reduce the Participant’s
forecasted CR requirement included in the PRM and will not be able to exceed that
value in meeting the Participant’s FS capacity requirement.
Customer resources can be aggregated to meet the FS Program minimum requirement
of 1 MW. Aggregated resources must reside in the same BAA and be controllable and
dispatchable. Behind-the-meter resources that have aggregated to the minimum 1 MW
threshold shall be treated and assigned QCC values as any other resource of similar fuel
type and must register with the PO.
Behind-the-meter resources that have not been aggregated and remain less than 1 MW
may not be visible to the PO. These non-controllable and non-dispatchable resources
will be considered load-modifying resources, and their impacts will be captured in the
Participant’s load forecast.
Resource Outages
2.5.7.1. Planned Outages
As is the practice currently, Participants will have full autonomy in planning their
generation outages. However, Participants are encouraged to plan outages, to the
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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extent possible, in advance of the FS deadline to minimize the occurrence of new
planned outages after the FS deadline.
Planned outages will not be taken into account in the QCC methodologies15 while
forced outages will be considered in the calculations for thermal resources. Planned
outages will be accounted for in a Participant’s FS portfolio. For a resource that has a
planned outage or capacity de-rate, the impacted portion of the resource’s QCC will be
decremented from the Participant’s shown capacity for the month(s) of the planned
outage.
Participants will provide planned outage information to the PO by the FS deadline by
including the planned outages in their FS portfolio (Figure 2-6). The information must
include the plant or unit on outage, the capacity (nameplate) impacted, and dates for
the outage. The PO will factor in the planned outage when assessing the Participant’s FS
portfolio to determine if the Participant is adequate or deficient.
To avoid a deficiency in the FS Program that may be caused by a potential planned
outage, Participants may acquire capacity for the month(s) of the binding season that
are impacted. The replacement/substitute capacity will need to meet all supply
requirements of the original capacity – including unit registration, contract
qualifications, transmission service demonstration, etc. If the substitution is
accomplished by a power supply contract, at a minimum, the term of the contract shall
be for the entire duration of the outage. Lack of adequate documentation may result in
the substitution not being accepted by the PO.
If a proposed planned outage in the FS Program that comprises a partial month causes
a potential deficiency, for which the Participant has not demonstrated substitution, a
qualified acceptance may be provided by the PO provided the deficiency is for less than
five days and the deficiency is less than 500 MW. This qualified acceptance is based on
the condition that the Participant will either acquire the required capacity prior to or in
the operational timeframe – or will receive an exception to provide the capacity from
the PO in the Ops Program. If the Participant does not either acquire the capacity prior
to or in the operational timeframe or receive an exception from the PO, deficiency
payments will apply as they are determined by the Ops Program.
15 At Participant option – planned outages may be included in storage hydro QCC calculations.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Some planned outages may need to occur after the FS deadline due to a variety of
reasons including a change in the scope of maintenance work, contractor availability, or
unforeseen issues. For planned outages that are scheduled after the FS deadline:
• Participants with portfolio QCC, net of the planned outage that exceeds their FS
capacity requirement: no action required.
• Participants with portfolio QCC, net of planned outage that is less than their FS
capacity requirement: will still be expected to have access to capacity sufficient to
meet FS capacity requirement during the Ops Program, should take measures to
ensure additional capacity is available to cover net difference.
• The PO will compile all outages by resource, MW and QCC impact, start date, and
end date to provide to the Ops Program for further upkeep and maintenance
during the operations timeframe.
• This process will be further fleshed out during program implementation.

Figure 2-6. Planned Outages.

2.5.7.2. Forced Outages
The QCC methodologies for the various types of resources each consider the impact of
forced outages when determining the QCC.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Construction of a Participant’s
Forward Showing Portfolio
A Participant’s FS capacity requirement, the QCCs of their resources and contracts, and
their FS portfolio compliance will be calculated and reported16 at a monthly granularity.
All calculations described throughout this section will be performed for each month of
the binding season. The Participant will be responsible for providing the necessary
information to the PO, who will complete the final calculations to determine if the
Participant has met their FS capacity requirement.
Participants may review input data for their respective systems. Participants may not
review input data of any other system or data supplied by other Participants. If required
by law, the PO may allow the review of data by regulatory and oversight bodies.
Resource QCC
As described in Section 2.4.1, each Participant will register all its owned generating
resources by providing the registration data required by the PO. The PO will calculate
the QCC for all resources owned by the Participant (except for storage hydro resources,
which will be calculated by Participant using the NWPP Storage Hydro QCC
Methodology and reviewed by the PO) in accordance with the applicable subsection of
Section 2.5. As necessary, planned outages will be considered when de-rating each
resource’s available monthly QCC. The summation of all QCC values for each Participant
owned resource is referred to as the Participant’s “resource QCC,” which will be
calculated for each month of a binding season.
𝑹𝒆𝒔𝒐𝒖𝒓𝒄𝒆 𝑸𝑪𝑪
=∑𝑸𝑪𝑪 𝒐𝒇 𝒂𝒍𝒍 𝑷𝒂𝒓𝒕𝒊𝒄𝒊𝒑𝒂𝒏𝒕 𝒐𝒘𝒏𝒆𝒅 𝒓𝒆𝒔𝒐𝒖𝒓𝒄𝒆𝒔

Net Contract QCC
As described in Section 2.4.2, Participants will provide all RA contracts (purchases and
sales) to the PO for verification of FS Program requirements. The PO will assign a
16 QCC will be calculated for thermal resources on a seasonal basis but will be used on a monthly basis –
each month of the season will have an identical QCC unless other factors such as planned outages impact
this value.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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monthly QCC value to all contracts provided prior to the FS deadline, dependent upon
the nature of the contract (described more fully in Section 2.4.2).

Once all contracts have been verified and assigned a QCC (i.e., the contracts have been
qualified), the net contracted QCC will be calculated on a monthly basis for each
Participant’s contracts (see example in Appendix F - Table 2-30). For accounting
purposes, import contracts (purchases) are additive to the Participant’s QCC value and
exports (sales) are a negative QCC value. The net QCC of all a Participant’s contracts is
the ”net contract QCC,“ and is calculated monthly for the binding season.
𝑵𝒆𝒕 𝑪𝒐𝒏𝒕𝒓𝒂𝒄𝒕 𝑸𝑪𝑪
=∑𝑸𝑪𝑪 𝒐𝒇 𝒂𝒍𝒍 𝑷𝒂𝒓𝒕𝒊𝒄𝒊𝒑𝒂𝒏𝒕 𝒒𝒖𝒂𝒍𝒊𝒇𝒊𝒆𝒅 𝒄𝒐𝒏𝒕𝒓𝒂𝒄𝒕𝒔

Resource Adequacy Transfers
Resource adequacy transfers are added to the purchasing Participant’s QCC value and
subtracted from the selling Participant’s QCC value. The contracts for these transfers will
be provided to the PO for validation.
𝑻𝒐𝒕𝒂𝒍 𝑹𝑨 𝑻𝒓𝒂𝒏𝒔𝒇𝒆𝒓
=∑𝑷𝒂𝒓𝒕𝒊𝒄𝒊𝒑𝒂𝒏𝒕 𝑹𝑨 𝒕𝒓𝒂𝒏𝒔𝒇𝒆𝒓 𝒄𝒐𝒏𝒕𝒓𝒂𝒄𝒕𝒔
Operational considerations indicate that it may be important for Participants to be
exclusively sellers or exclusively purchasers of RA transfers. Further consideration will be
given in future phases to whether a ‘net’ approach is feasible.

Forward Showing Portfolio and Calculation
A Participant’s total portfolio QCC is defined as the Participant’s resource QCC plus their
net contract QCC plus their total RA transfer.
𝑷𝒐𝒓𝒕𝒇𝒐𝒍𝒊𝒐 𝑸𝑪𝑪
=𝑹𝒆𝒔𝒐𝒖𝒓𝒄𝒆 𝑸𝑪𝑪+𝑵𝒆𝒕 𝑪𝒐𝒏𝒕𝒓𝒂𝒄𝒕 𝑸𝑪𝑪
+ 𝑻𝒐𝒕𝒂𝒍 𝑹𝑨 𝑻𝒓𝒂𝒏𝒔𝒇𝒆𝒓

Each Participant’s portfolio QCC should be at least equal to the Participant’s FS capacity
requirement for each month of the binding season. Provided the Participant’s portfolio
QCC has met or exceeded that threshold, the FS capacity requirement has been
satisfied.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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𝑷𝒐𝒓𝒕𝒇𝒐𝒍𝒊𝒐 𝑸𝑪𝑪≥𝑭𝑺 𝑪𝒂𝒑𝒂𝒄𝒊𝒕𝒚 𝑹𝒆𝒒𝒖𝒊𝒓𝒆𝒎𝒆𝒏𝒕

Any portfolio QCC in excess of the Participant’s FS capacity requirement is considered
outside of the Program. A Participant’s additional planned maintenance or short-term
sales will be made from their excess Portfolio QCC. Table 2-9 presents an example of a
FS portfolio and calculation.
Table 2-9. FS portfolio summary example.
FS Monthly Summary
Month
FS Capacity
Requirement
(P50+PRM)
Portfolio
QCC
Additional
Planned
Outages (if any)
Met FS Capacity
Requirement
2022-11 1125 1125.5 0 TRUE
2022-12 1125 1295.5 0 TRUE
2023-01 1125 1475.5 250 TRUE
2023-02 1125 1543.5 300 TRUE
2023-03 1125 1225.5 75 TRUE

Deficiency Payment for
Noncompliance
If a Participant fails to meet their FS capacity requirement after the cure period, the FS
Program will assess some multiple of a CONE payment against the noncompliant
Participant (see Table 2-10). The CONE is based on publicly available information (i.e.,
information provided by the Energy Information Administration) relevant to the
estimated annual capital and fixed operating costs of a hypothetical natural gas-fired
peaking facility. The CONE value does not consider the anticipated net revenue from the
sale of capacity, energy, or ancillary services nor does it consider variable operating
costs necessary for generating energy.
The RA Program’s CONE value will be derived by the PO and reviewed annually; any
changes will be proposed by the PO pursuant to the RA Program rules and approved by
the appropriate governing body or committee pursuant to the RA Program rules. The
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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CONE deficiency payment is intended to be significant enough that Participants are not
expected to fail to meet their FS capacity requirement with any regularity and are
encouraged to act in good faith to address their respective share of RA. Any FS
payments assessed to Participants will be used to offset costs of the Program.
Table 2-10. CONE Payment.
Proposed Calculation for Deficiency Capacity and Payment
𝑬𝒏𝒕𝒊𝒕𝒚’𝒔 𝑫𝒆𝒇𝒊𝒄𝒊𝒆𝒏𝒄𝒚 𝑪𝒂𝒑𝒂𝒄𝒊𝒕𝒚 (𝑴𝑾)
= 𝑷𝒐𝒓𝒕𝒇𝒐𝒍𝒊𝒐 𝑸𝑪𝑪
−(𝑭𝒐𝒓𝒘𝒂𝒓𝒅 𝑺𝒉𝒐𝒘𝒊𝒏𝒈 𝑹𝒆𝒔𝒐𝒖𝒓𝒄𝒆 𝑹𝒆𝒒𝒖𝒊𝒓𝒆𝒎𝒆𝒏𝒕
+𝑹𝑨 𝑻𝒓𝒂𝒏𝒔𝒇𝒆𝒓𝒔 )
𝐄𝐧𝐭𝐢𝐭𝐲’𝐬 𝐃𝐞𝐟𝐢𝐜𝐢𝐞𝐧𝐜𝐲 𝐏𝐚𝐲𝐦𝐞𝐧𝐭/𝐏𝐞𝐧𝐚𝐥𝐭𝐲 = 𝐃𝐞𝐟𝐢𝐜𝐢𝐞𝐧𝐭 𝐂𝐚𝐩𝐚𝐜𝐢𝐭𝐲×
𝐂𝐎𝐍𝐄 × 𝐂𝐎𝐍𝐄 𝐟𝐚𝐜𝐭𝐨𝐫
CONE Factor:
− 125% @ FS Program has capacity in excess of 8 percent (or greater)
above the required PRM.
− 150% @ FS Program has capacity excess of more than 3 percent above,
but less than 8% above the required PRM.
− 200% @ FS Program has capacity excess of less than 3% above the
required PRM.

Transmission and Deliverability
At the FS deadline, Participants must demonstrate having transmission rights to deliver
at least 75% of its FS resources claimed in the FS portfolio from RA resource to load (for
at least the QCC value associated with a specific resource). Transmission demonstrated
must be (at minimum) NERC priority 6 or 7 transmission service.
Transmission rights demonstrated will be associated with specific resources claimed in
the FS portfolio to support the requirement to demonstrate transmission from ‘resource
to load.’ Contracts requiring use of NERC priority 6 or 7 transmission will satisfy this
requirement.
If a Participant intends to use 6-NN / 7-FN to satisfy this requirement, they must
demonstrate to the PO (e.g., via written contracts/approval from their applicable TSP)
their ability to use network service; 6-NN reservations need not be shown for the leg to
which they apply, if the Participant adequately demonstrates their ability to use such
service. In future phases, the RA Program must consider how paths constrained for 7-FN
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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will be handled. On these
constrained paths, 6-NN may not
be acceptable (this would be TSP
specific)
The PO may request additional
details from Participants to confirm
contracts and/or supporting
agreements used in the FS
portfolio comply with the FS
transmission eligibility
requirements. Business processes
and specific showing expectations
will be determined in Phase 3A. Examples of additional information the PO may require
include:
• Confirmed priority 6/7 transmission reservations
• Demonstration of ability to use 6-NN service
• Transmission provisions in supply contracts claimed in entities’ FS portfolio
Participants will also indicate an expected transmission path for the remaining 25% of
resources shown in their FS portfolio. These expectations are informational only. The PO
will aggregate this information in the FS window to the flowgate level to view
anticipated additional transmission needs. In Phase 3A, additional consideration will be
given to the ability to utilize this data for additional situational awareness or planning
purposes (e.g., providing to TSPs 2-5 months in advance of the season for consideration
in planning maintenance or advising on potential issues). Use of this data would be
conditional upon it being appropriately aggregated or otherwise protected to ensure
confidential or commercially sensitive data is not shared or used inappropriately, as
determined in these upcoming discussions.
If a Participant has not demonstrated sufficient procurement of transmission rights or
contracts and/or specified necessary transmission information by the FS deadline (at
least 75% of their FS capacity requirement, but taking into consideration approved
exceptions), the Participant can remedy during the established two-month cure period
to avoid a FS failure penalty (see section 2.1 for additional detail).
Participants are expected to use good faith efforts to timely cure any other changes to
its transmission arrangements after the FS demonstration. The FS Program will utilize a
Examples
Example 1: if Participants have an on-system
resource, they must demonstrate a TSP will allow
6-NN to be counted and that they have rights to
6-NN
Example 2: an off-system resource, Participant
must demonstrate that a TSP will allow 6-NN to
be counted, that they have access to 6-NN, +
must show priority 6/7 transmission to the local
TSP boundary.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 87 of 254
zonal approach to evaluate the ability of the NWPP system to support generation-to-
load transfers and facilitate the utilization of generation diversity across the RA Program
footprint.
Showing Exceptions
Given the need to work within existing transmission frameworks, there may be situations
requiring exception from the basic FS requirements identified above. Exceptions will be
evaluated by the PO on a case-by-case basis to ensure reliability of the RA Program will
not be impacted.
If insufficient NERC priority 6 or 7 transmission service is available prior to the FS
deadline on a specific path (or in a specific circumstance), a Participant may request an
exception from the 75% requirement. Requests will be dependent on what type of
exception is sought. Examples include:
• Exception due to an enduring constraint that affects a Participant’s ability to
deliver showing resources to load on firm transmission.
In this circumstance, the value of the exception would be subtracted from
total portfolio QCC value, and Participant would demonstrate having
appropriate transmission rights or contracts for 75% of remaining QCC
value.
The Participant will work with the PO and TSP (as applicable) to identify an
approved (near-term and longer-term) mitigation plan to remedy this
issue (e.g., building additional resources local to load pocket, have entered
transmission queue for long term service). This exception is not intended
to be indefinite, indicating that the Participant must be able to
demonstrate pursuit of this plan.
• Exception due to a particular path or circumstance where short-term firm
transmission is consistently available but not posted on a long-term basis, such
as firm counterflow transmission.
In this circumstance, the Participant may petition to acquire this
transmission after the FS period. An approved exception of this type
counts is considered demonstration of transmission for impacted RA
resources and counts toward the 75% requirement
• Exception due to excessive outages: Participant demonstrates that the constraint
is temporary and requests an exception for the time of the outages.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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An approved exception of this type counts is considered demonstration of
transmission for impacted RA resources and counts toward the 75%
requirement
Further consideration of the exception process is intended for upcoming phases.
Load Resource Zones
Load and resource zones (LRZs) have been identified at the end terminus of major
transmission constraints or paths, considering interties and the critical flowgates within
(and ties to) Participants’ footprints (see Appendix E). For example, loads located west of
the Cascades have been designated as an LRZ.
If a local zone cannot access capacity from Participants outside the zone because of
transmission congestion, then Participants within that zone may need to procure an
additional local capacity for the season to maintain system reliability.
Details regarding the ability of specific LRZs to support load within the zone and the
need for additional import capability, whether through the acquisition of firm service or
other means of constructing new transmission infrastructure have not yet been fully
determined. These details will also help in the determination of whether certain LRZs will
be required to have a higher PRM than the Program requirement.
Additional details of the transmission and deliverability process can be found in
Appendix E.
Modeling Data from the FS
Program Provided to the Ops Program
Upon completion of FS Program processes, a minimum of two months prior to the start
of the binding season, the focus of the RA Program will shift to the Ops Program. The FS
Program will provide the inputs listed in Table 2-11 to the Ops Program. The details of
data submission requirements will be developed in the next phase of the project.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Table 2-11 FS Program inputs to the Ops Program
Non-Coincident Peak (NCP) P50 load
provided in FS Notes
P50 will be a Participant peak value (equivalent to an NCP, not coincident with
FS Program peak)
PRM will be on a UCAP, NCP basis
Outside of CR implications, most
Participants should have the same PRM
requirement – unless they are located in a
transmission constrained area
Portion (if any) of CR that are included in the
PRM will be stated (i.e., all CR are included,
50% are included, etc.).

Resources:
ICAP MW value – accomplished through unit
testing.
List of planned outages submitted in the FS
portfolio.
QCC value – accomplished through UCAP
analysis
QCC (UCAP) MW value – accomplished
through review of outages [EFOF(CCH)].
Planned outages
DR resources
QCC values
Contract imports (fleet)
QCC values
Contract imports (resource specific – not registered)
QCC values
Contract exports
ICAP values

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Modeling Process Timelines
The RA model will be capable of supporting regular analyses with repeatable findings
and will be transparent and auditable by Participants, utility regulatory and oversight
bodies, and other regional stakeholders to the extent possible.17 It is recommended the
model input data be updated with a corresponding stakeholder process and model
results shared with Participants before each FS deadline. Protocols will be adopted
allowing detailed and/or confidential information to be shared with specific Participants
for review and vetting and aggregated information to be shared with all Participants.
Each year, the PO will begin a new set of annual LOLE/PRM and QCC assessments
(annual assessments) that will be used for determining the PRM and QCC for FS
Program resources. These studies are to be completed each year no later than October
31 for the Summer season and no later than March 31 for the Winter season to allow 12
months for Participants to prepare for the next binding season. Proposed modeling
timelines are illustrated in Figure 2-7.
Figure 2-7 outlines the timelines associated with both the Summer and Winter season
modeling processes. It should be noted that the terminology T-X is used with regards to
the calendar year in which these deadlines occur. In this terminology, T-2 would be the
upcoming or current calendar year, T-1 would be one year out in the future, T-0 would
be two years out, and T+3 would be five years out.
Each year, the PO will begin a new set of assessments that will be used for determining
the PRM and QCC for program resources. There will be one study run for the Summer
season and one study run for the Winter season. Both studies will follow a similar
process. The process will begin with a data request sent to Participants by the PO.
Participants will then submit data to the PO and be given a chance to review their model
inputs prior to the model being run. Once the model has been run, the PO will provide
Participants with their draft model outputs and allow time for Participants to review
these model outputs prior to the study completion dates. Study results will be finalized
12 months prior to the associated FS deadline.
17 Individual Participant data will not be available to anyone except the Participant and the PO for
confidentiality.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 91 of 254
MODELING PROCESS TIMELINES
Jan 15th
PO sends data request for Model Build
Feb 1st
Participants provide data
PO provides modeling inputs to Participants for review
May 1st
Participant review of modeling inputs due
Jun 1st Sep 15th
PO provides draft model outputs for review
Oct 15th
Participant review of draft model outputs due
Binding Season
Oct 31st Jun 1st
Year T-2 Year T-1
Jun 1st
Year T-0
Jan 1st Jan 1st
Studies Complete
Summer
Winter PO sends data request for Model Build
Participants provide data (potential
for more time here)
PO provides modeling inputs to Participants for review
Participant review of modeling inputs due
PO provides draft model outputs for review
Participant review of draft model outputs due
Binding SeasonCure Deadline
Jan 15th Feb 1st Oct 1st Nov 1st Feb 15th Mar 15th Mar 31st Jan 1st
Year T-2
Nov 1st
Year T-0
Nov 1st
Year T-1
Jan 1st
Oct 31st
Forward Showing Deadline
Mar 31st
Studies Complete
Feb 28th
Cure Deadline
Jul 31st
Showing Deadline
PO issues Forward Showing data request
PO issues Forward Showing data request
Forward
Modeling and Assessment Process Forward Showing Process Binding
Season

Figure 2-7. Proposed Modeling Process Timelines.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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SECTION 2: APPENDIX A - ANNUAL
ASSESSMENTS
A.1. Planning Reserve Margin
The PO will calculate the PRM for the RA Program footprint annually for both the
Summer and Winter binding seasons during the Annual Assessment process. Annual
assessments will be completed at least 12 months in advance of the FS deadline for the
following year. Studies for the Summer season will be completed by Oct 31 (T-2); studies
for the Winter season will be completed by March 31 (T-1). See Table 2-12.
Table 2-12. Timing the determination of Summer season PRM.
Example: Timing of the determination of Summer season PRM
In calendar year 2025 (T-2), FS Program Participants provide data to the PO, who
completes the Summer season study by October 31, 2025.
− The study determines a binding PRM for the 2027 (T-0) Summer season.
− The study determines an advisory PRM for the 2030 (T+3) Summer season.
In calendar year 2026 (T-2), the process begins anew, and the Summer season study is
completed by October 31, 2026.
− This study provides a binding PRM for 2028 (T-0) Summer season.
− This study provides an advisory PRM for 2031 (T+3) Summer season.

A.1.1. Qualified Capacity Contribution
The PO will calculate the QCC of all FS Program resources on an annual basis as part of
the Annual Assessment process. This calculation is handled in accordance with the
resource type. QCC analyses and ELCC studies will be performed annually for each
Summer and Winter binding season. The completion dates will be no later than October
31 (T-2) for the Summer season, and March 31 (T-1) for the Winter season.
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A.2. Model Input Update Process
To support the annual assessments, the PO will develop an RA model that represents
the RA Program footprint. Inputs to this model will be submitted by the Participants and
will represent each of the Participant’s systems. No later than January 15 of each
calendar year, the PO will send out updated data requests to the Participants for the
items described in Table 2-13 necessary to complete the annual assessment for that
calendar year.
Table 2-13. Participant Provided Modeling Data.
Annual Assessment Data Items
Load data - Participant 8,760-hour actual historical load data for the previous year (initial
request will need at least 10 years of data, subsequent request will add an additional year
annually)
Separate load shapes that are split between different zones
Historical temperature values, for each area/load center, for the previous year (initial
request will need at least 10 years of data)
Participant conventional resource data for new units added during the previous year (initial
request will include data for all Participant units) including:
− Fuel type
In-service and retirement date (if known)
− Wind, solar, run-of-river resources (by resource) added in the previous year (initial
request will include all units)
Hourly generation profiles for the last 10 years (for existing units)
ICAP by hour (for existing units)
All data required by the NWPP Storage Hydro QCC Methodology necessary to determine
QCC for resources (i.e., data needed to populate the NWPP Storage Hydro QCC Workbook)
NERC GADS or equivalent outage data that can be used to calculate equivalent forced
outage rates (EFOR) for the last six years (for existing units)
Minimum capacity
The PO will need to receive all information from Participants no later than February 1 of
each year.
Some data from previous FS submittals may be used for the annual assessments. The
data points in Table 2-14 will be taken from the Participant’s previous FS submittal. New
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Participants to the Program will be required to provide these data points in a separate
request.
Table 2-14. Modeling data taken from FS submittals.
Data Items
Firm import/export transactions that each Participant wants included in the forward-
looking model (one-three years in the future)
Capacity value of transaction
DR program/resources
Forecast peak demand
Timeframe of transaction

A.3. Participant Review and Verification
Process of Input Data
Once the PO has input all necessary data into the RA model, Participants will be allowed
to review the input data (in the format used by the RA model or a format developed by
the PO) for their respective systems. This review will occur between May 1 –June 1 (T-2)
for the Summer season and between October 1 - November 1 (T-2) for the Winter
season. This review will occur before the PO begins model simulations.
As stated previously, Participants may review input data for their respective systems.
Participants may not review input data of any other Participants. If required by law, the
PO may allow the review of data by regulatory and oversight bodies.
A.4. Draft Modeling Output Results
Sharing
By September 15, T-2 (for the Summer season), and February 15, T-1 (for the Winter
season), the PO will provide draft modeling results to the Participants for their review.
The modeling outputs that will be available for Participant review are listed in Table
2-15.
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Table 2-15. Output from modeling results.
Outputs
Resource index
QCC values by resources owned or contracted by the Participant
Proposed PRM for the season under study
Peak coincident load of the RA Program footprint
Transmission limitations (if the Participant is located in a transmission-constrained zone)

Participants will have the opportunity to review the draft results and work with the PO to
analyze any potential discrepancies from expected results. Any discrepancies will be
reviewed and resolved no later than October 15 (T-2) for the Summer season and March
15 (T-1) for the Winter season.
A.5. Final Modeling Output Results
Sharing
The final modeling output results provided by the PO will consist of a LOLE study report
that: gives details of the study analysis; makes recommendations for a proposed PRM
for the year two binding season; provides an advisory PRM for the year five
Summer/Winter season. QCC studies/reports will include the ELCC studies for wind,
solar, and run-of-river hydro, as well as QCC results for storage hydro resources, thermal
resources, short-term storage resources, and customer resources. A summary of studies
and the output results are provided in Table 2-16.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Table 2-16. Final Modeling Output Results.
Study Output Results
LOLE − PRM for the upcoming binding Summer/Winter season.
QC
C

S
t
u
d
i
e
s

VER (ELCC)
− QCC values by month for all wind, solar, run-of-river resources.
− QCC values for all wind, solar and run-of-river resources will be
available to all Participants.
Thermal (UCAP)
− QCC values by month for all thermal resources.
− QCC values for all thermal resources will be available to
Participants.
o Calculations for determining the QCC of thermal
resources will be available to the resource owner.
Storage Hydro
(NWPP Storage
Hydro QCC
Methodology)
− QCC values by month for all storage hydro resources.
− QCC values for all storage hydro resources will be available to all
Participants.
o Calculations for determining the QCC of storage hydro
resources will be available to the resource owner.
Short-Term
Storage (ICAP
Testing and
hybrid resources
– “Sum of Parts”)
− QCC values by month for all short-term storage and hybrid
resources.
− QCC values for all short-term storage and hybrid resources will
be available to all Participants.
o Calculations for determining the QCC of short-term
storage and hybrid resources will be available to the
resource owner.
Customer
Resources
(capacity resource
or load modifier)
− QCC values by season for customer-side resources.
− QCC values for all customer side resources will be available to all
Participants.
o Calculations for determining the QCC of customer side
resources will be available to the resource owner.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 97 of 254
SECTION 2: APPENDIX B - MODELING
ADEQUACY STANDARD AND PRM
B.1. Introduction
Determination of the PRM will be supported by a probabilistic LOLE study, which will
analyze the ability of generation to reliably serve the RA Program footprint’s P50 load
forecast. The PRM will be studied such that the LOLE (while maintaining CRs) for the
applicable planning year does not exceed one event in 10 years for the Summer season
and one event in 10 years for the Winter season. At a minimum, the PRM will be
determined using probabilistic methods by altering capacity through the application of
generator forced outages and forecast demand through the application of load
uncertainty to ensure the LOLE does not exceed the aforementioned reliability metrics.
B.2. Software Used
The LOLE study will be performed using a software that is capable of performing LOLE
and ELCC analyses. The software may be an industry recognized software package or
may rely on custom developed elements or packages to support the design of the
Program. The software should be readily supportable and adaptable to evolutions of the
Program.
B.3. Area Modeling
For the LOLE study, RA Program footprint will be modeled as LRZs that have been
determined in discussions with the RA Program Participant transmission group and area
TSPs (see Section 2.8). If a specific LRZ is determined to be transmission constrained,
that the constrained LRZ may have a higher PRM requirement applied than the
remainder of the RA Program footprint.
The LOLE study will utilize a pipe and bubble methodology for modeling the
transmission system. The load and resources of an individual LRZ will be modeled as a
“bubble” representing each zone. For the LOLE simulations, import and export
capabilities (“pipe sizes”) between LRZs will not be constrained when determining the
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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footprint’s PRM value. After the footprint’s PRM value has been found, an analysis of
each LRZ will be made to determine if a zone is transmission constrained and must be
addressed as detailed in Section 2.8.2.
B.4. Load Modeling
Historical hourly load data from the previous 10 years will be used to produce 8,760
hourly load profiles for each LRZ. The historical data will be provided by Participants in
the annual data request. If a Participant’s load spans more than one LRZ, then the
Participant will need to submit their data based on each LRZ in order to adequately
model each Participant’s peak demand and load shapes for the applicable LRZs.
The median historical peak year will be determined for each season (Summer or Winter).
The median year (for each season) will then be scaled to match the Participant provided
forecast peak loads for the years studied for the LOLE analysis. For example, if year 2014
is the median peak year for weather years 2011 to 2020 Summer seasons, then the load
shape for that calendar year will be scaled to the forecasted peak demand of the
applicable study year (either year (T-0) binding or year (T+3) advisory). If the actual
Summer peak demand for 2014 was 1,000 MW and the forecasted demand is 1,100 MW,
then the peak, along with all hours in the applicable season, will be scaled up by 10%. If
2012 had a historical peak of 1,200 MW, then the relationship between 2012 and 2014
will still be represented by scaling the 2012 Summer season weather shape up by 10%
as well.
For multiple Participants located in one LRZ, their load shapes will be aggregated into a
single load shape and the loads will be scaled to the appropriate LRZ peak. Load and
time zone diversity will be considered when deriving the load shapes for each zone in
such a manner that the modeled forecasted peak of each zone is not overstated by
simply adding the P50 peaks of all Participants in a zone and setting that value as the
peak.
B.4.1. Load Forecast Uncertainty
Load forecast uncertainty (LFU) is an important component in an LOLE study and can be
represented in multiple ways depending on the capability of the software used. The
following method should be adequate if monthly load uncertainty can be derived either
using economics, historical weather patterns based on temperature, or historical rain fall
amounts, or the main underlining factor driving load uncertainty and variability for each
Participant’s load and can be adequately represented probabilistically. The LFU should
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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include deviations below and above the 50th percentile to capture the full array of
forecast uncertainty deviations from a “P50” forecast.
A user-defined uncertainty pattern and a probability distribution will be used to add
uncertainty to the load values. A different load uncertainty distribution pattern will be
modeled monthly for each LRZ. A load model will the peak-demand multipliers used to
modify forecast peak demand. The daily peak is selected and regressed against
historical peak temperatures, previous day’s peak load, weekday or weekend
identification, and holiday identification from the previous 10 years.
The probability distributions of temperatures observed at key weather stations
throughout the RA Program footprint will be analyzed. A forecast will then be created
for both study years (T-0 and T+3). Based on the forecasts, multipliers will be calculated
and populated in a user-defined uncertainty pattern. The user-defined uncertainty
pattern allows users to provide seven monthly demand patterns. Each LRZ has a
different value for each month multiplied by seven probabilities (84 values). The load
uncertainty allows for unexpected increases of demand in addition to the adjusted
testing reserve margin.
B.5. Generation Modeling
B.5.1. Thermal Generators
Thermal generators will be modeled as units at their ICAP tested values with forced
outages and planned outages applied as necessary in accordance with their EFOR18 and
planned outage rates. The ICAP values will be provided by each Participant in their
annual data submittal. All thermal resources will be modeled in the LOLE and ELCC
studies, unless otherwise noted by a retirement date, future in-service date, or for any
other reason identified by the Participant.
Forced outage modeling for thermal resources will consist of using the EFOR values
(EFOR equation as defined by NERC GADS), forced outage durations and maintenance
scheduling parameters, and outage events sourced from NERC GADS (or equivalent)
18 EFOR is a metric used in the LOLE study for determination of system PRM. This is a different metric than
is being used for the determination of QCC for thermal resources (EFOF). EFOR takes system outages,
regardless of time during the year, including potential extreme events and events outside of plant
management control, into account for the determination of PRM. The determination of QCC is plant
focused, determined primarily on CCH, and excludes outages outside of plant management control.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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data provided by Participants. For thermal resources that do not submit such data, an
average forced outage rate will be applied based on size, fuel type and age of the
resource. At least 5 years of historical NERC GADS (or equivalent) data will be
considered in the LOLE and ELCC analysis. All ELCC and LOLE studies will use the same
outage rates and method for the modeled resources. The models will be updated every
year to reflect the latest outage rates.
Planned outages for thermal resources will be modeled using the LOLE software’s
scheduled maintenance function (e.g., SERVM by Astrapé) by switching the status of
each resource to “offline” to account for expected outage duration and unit start time.
Previous planned outages will be taken into consideration when modeling the
maintenance window for each resource. For Monte-Carlo based software, annual
maintenance rates and planned outage rates will be considered at a minimum for all
thermal generators, as determined by the historical NERC GADS (or equivalent) data.
A “commit all” approach will be used for Monte-Carlo based software, meaning all
resources will be treated as available at any given hour if the resource is not on outage.
Use of physical unit limitations may be considered in the future as the RA Program
evolves.
B.5.2 Storage Hydro
The NWPP Storage Hydro QCC Methodology will establish QCC values for all storage
hydro plants on a monthly basis. For the LOLE study, storage hydro plants will be
modeled at their QCC values for each month. The methodology utilized to assess QCC
values for hydro facilities accounts for the availability of storage such that in the LOLE
modeling, it is appropriate to assume the facility has enough stored energy to output
the monthly QCC value for each hour in the simulation. No outage information will be
applied to the resources in the simulation, since the QCC values also already consider
historical outages.
B.5.3 Wind, Solar, Run-of-River Resources
The study model will include all wind, solar, and run-of-river hydro resources currently
installed or proposed to be in-service in the RA Program footprint prior to the study
year; hourly generation profiles will be assigned to each resource. Hourly generation is
based upon historical profiles correlated with the yearly load shapes (previous 10 years),
as provided by Participants. New facilities that do not have historical generation profiles
will be assigned shapes consistent with the resource-specific zone in which they are
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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located or assigned historical shapes by the nearest site; alternatively, Participants can
submit forecasted shapes based on historical hourly meteorological data .
B.5.4 Demand Response Programs
When controllable and dispatchable DR is reported in FS portfolios, equivalent thermal
resources will be added to the model with high fuel costs, such that these representative
”thermal” resources would be dispatched last by the model to reflect DR operating
scenarios. Forced outage rates will not be assigned to the DR programs. Any DR Ops
Program restrictions provided by the Participant will be modeled in the LOLE study. DR
programs not reported in the data submissions should be considered as load reductions
in the P50 forecasted peak demand for each season.
B.5.5 Behind-the-Meter Generation
Behind-the-meter generation reported by Participants as capacity resources that are
controllable and dispatchable by the Participant will be modeled as generation. See also
Customer Resources Section 2.5.6. These resources will be assigned parameters and
forced outage information from equivalent-sized resources. Behind-the-meter
generation not reported in data submissions would be accounted for in load reductions
in the P50 forecasted peak demand for each season.
B.5.6. External Capacity Modeling
Any external capacity transactions that are supported by firm commitments in the FS
portfolios will be modeled as hourly generators in the applicable LRZ. External
transactions are any firm capacity transactions or obligations to non-participating
entities either internal or external to the RA Program footprint. If the transaction is a sale
to a non-participating entity, it will be an export of capacity. If the transaction is a
purchase from a non-participating entity, it will be modeled as an import of capacity;
forced outage rates will not be assigned to these transactions.
Non-firm regional interchange will be modeled in LRZs that border adjacent BAAs south
of the RA Program footprint, which may include non-participating entities in California,
New Mexico, and Arizona.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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B.6. Determination of 1 Event-Day in 10-
Year Threshold
For the LOLE study, loss of load events will be tabulated during the hours of the binding
season for determination of the 1-in-10 LOLE metric. Loss of load events that occur
during hours outside of the binding season will not be included in the calculation of the
PRM.
Pure negative (or pure positive if the system is generation deficient) capacity with no
outage rate will be added to the model until the RA Program footprint reaches the 0.1
day per year reliability threshold. The pure negative (or positive) capacity value assigned
in the LOLE study will be the same amount for all hours in the season of interest.
Summer and Winter season PRMs will be determined separately.
B.7. PRM Calculation
As discussed in Section 2.2.2, the Program PRM will be given on a UCAP basis. To
calculate the PRM on a UCAP basis, the capacity value determined in Section B.6 must
be converted to a UCAP value (see Table 2-17 for details on this conversion).
Table 2-17. Resource capacity conversion to UCAP for PRM calculation.
Resource type Conversion to UCAP
Thermal Generation UCAP capacity values from the QCC analysis are used to replace the
ICAP (nameplate) value of all thermal resources.
VER UCAP capacity values for each VER type will be taken from the QCC
VER amounts calculated from the RA Program ELCC analysis.
Storage Hydro No conversion needed - The QCC values determined through the
Hydro QCC method will be used in the calculation.
Short-term storage/
hybrid resources/
Demand Response
(DR)
No conversion needed - ICAP capacity (at the Program time
duration requirement) is used for the UCAP calculation.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Pure Capacity
adjustment to meet
1-in-10 LOLE
No conversion needed.

After the UCAP conversion is complete, the UCAP PRM is calculated:
𝑷𝑹𝑴 (𝑼𝑪𝑨𝑷) (%)
= 𝑪𝒂𝒑𝒂𝒄𝒊𝒕𝒚 (@𝟏−𝒊𝒏−𝟏𝟎)−𝑫𝒆𝒎𝒂𝒏𝒅
𝑫𝒆𝒎𝒂𝒏𝒅∗𝟏𝟎𝟎

B.8. Simulation Process
The probabilistic LOLE study will model random forced outages for resources in the RA
Program footprint during each hour of the study. Each simulation will account for a
different variation of forced outages, wind output, and load uncertainty for all hours of
the year. The stop criterion for the modeling simulation is when the LOLE convergence
factor is greater than or equal to 95% for consideration of probabilistic indices. The
software will calculate the convergence factor to determine if additional simulations are
needed.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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SECTION 2: APPENDIX C - PRM
ALLOCATION METHODOLOGIES
The PRM represents a “safety margin” of capacity that is required by the RA Program
footprint to maintain the reliability of the area. For the most part, the PRM is determined
on a system-wide basis. Once the PRM has been calculated by the PO, each Participant’s
FS capacity requirement must be identified.
The FS Program will allocate the capacity requirement of the PRM to each Participant
based on their individual P50 load forecast using the NCP of each Participant. By
allocating the PRM requirement in this manner, Participants will have a simple,
straightforward method for determining their reserve requirement, with equal sharing of
load diversity benefits. Table 2-18 provides an example of the PRM capacity allocation
calculations.
The calculation appears as shown below:
𝑨𝒍𝒍𝒐𝒄𝒂𝒕𝒆𝒅 𝒄𝒂𝒑𝒂𝒄𝒊𝒕𝒚 𝒓𝒆𝒒𝒖𝒊𝒓𝒆𝒎𝒆𝒏𝒕=(𝑷𝒂𝒓𝒕𝒊𝒄𝒊𝒑𝒂𝒏𝒕′𝒔 𝑷𝟓𝟎 𝒍𝒐𝒂𝒅
∑𝑨𝒍𝒍 𝑷𝒂𝒓𝒕𝒊𝒄𝒊𝒑𝒂𝒏𝒕′𝒔𝑷𝟓𝟎 𝒍𝒐𝒂𝒅)∗
𝒓𝒆𝒈𝒊𝒐𝒏𝒂𝒍 𝒄𝒂𝒑𝒂𝒄𝒊𝒕𝒚 𝒏𝒆𝒆𝒅

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Table 2-18. Example PRM capacity allocation methodology calculations.
NCP load of the RA Program footprint = 5,025 MW
Participant “A” – P50 load = 1,000 MW (load at RA Program Peak = 950 MW)
Participant “B” – P50 load = 2,000 MW (load at RA Program Peak = 1,925 MW)
Participant “C” – P50 load = 2,200 MW (load at RA Program Peak = 2,150 MW)
Regional PRM is calculated to be 15% of the RA Program CP load through the
LOLE study
With the calculated PRM, the total capacity needed for the region is:
1.15*5,025 MW = 5,779 MW
The effective PRM for all Participants becomes:
PRM = 5,779 MW/5,200 MW = 11.1%
Calculation of capacity (can use equation above or if the effective PRM is known, multiply by
the effective PRM).
Participant “A” – (1,000 MW /5,200 MW) *5,779 MW = 1,111 MW
Or 1,000 MW * 1.111 = 1,111 MW
Participant “B” – (2,000 MW/5,200 MW) * 5,779 MW = 2,223 MW
Or 2,000 MW * 1.111 = 2,223 MW
Participant “C” – (2,200 MW/5,200 MW) * 5,779MW = 2,445MW
Or 2,200 MW * 1.111 = 2,445 MW

C.1. Impact of Contingency Reserves on
PRM
In accordance with standard BAL-002-WECC-2a, a BAAs total CR needs are based on the
requirement to carry reserves on three percent of hourly integrated load and three
percent of hourly integrated generation; this will result in different total requirements
depending on Participants’ generation portfolios and load profiles.
The LOLE study and resulting PRM assures that during a loss of load event, Participants'
CRs are maintained. To ensure this, the LOLE study assumes an average 6% CR
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 106 of 254
requirement when determining the PRM. Once the PRM for the region is identified,
appropriately allocating those CRs to Participants requires consideration of which
Participants are responsible for the 3% of generation CR obligation. For example, in
a scenario where Participants' P50 loads exactly match their portfolio QCC, the
allocation of the CR requirement to each Participant is equal to 6% of P50 load. Given
that we expect some Participants to own, operate, and register large fleets (greater
portfolio QCCs than their P50 loads), and others to rely primarily on importing
generation, we must adjust the showing requirement to reflect this nuance. To arrive
at a Participant's FS capacity requirement (accounting for differing resource positions),
the regional PRM (with the embedded 6% of P50 load assumption) will be adjusted
based on the net of a Participant’s purchases and sales submitted in the FS. A
Participant with a negative net of purchases and sales will be deemed to be a net
importer (assumes purchases as indicated with a negative (-) sign, as they decrease the
CR obligation). A Participant with a positive net of purchases and sales will be deemed
to be a net exporter. The adjustment to arrive at the FS capacity requirement will be ((-
purchases + sales) * .03). For a Participant with total purchases of 150 MW and total
sales of 100 MW the adjustment to the FS capacity requirement would be -1.5 MW or ((-
150 +100 * .03). For a Participant with total purchases of 150 and total sales of 300 the
adjustment to the FS capacity requirement would be 4.5 MW or ((-150 + 300) * .03).
Thus, the FS capacity requirement includes an approximation of a Participant's CR under
the circumstances modeled throughout the FS metric setting (a P50 load day where all
resources are performing at their QCC). The sharing calculation in the Ops Program
includes a delta CR term which will adjust for differences between the FS CR
assumptions and the forecasted CR obligations in the Ops timeframe.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 107 of 254
SECTION 2: APPENDIX D - QUALIFIED
CAPACITY CONTRIBUTION MODELING
D.1. Storage Hydro
D.1.1. Time Period Approach for Summer and Winter
Binding Requirements
The NWPP RA Program Development Project Steering Committee recommended that a
“time period” approach be taken to determine the potential Qualifying Capacity
Contribution (QCC) of storage hydro. A time period approach consists of a historical
look-back of the generation output during CCH to determine how much capacity should
be expected to be available during high load periods in the future. While this approach
is not intended to be perfect, it does establish a common and transparent method for
determining the QCC for storage hydro.
One of the main benefits of using a time period approach is that the methodology is
based on data that reflects the actual operation of the facilities during past high load
periods, and reflects the myriad of considerations, constraints and complexities that
went into the operation of the resources during those periods. It can be very difficult for
any model to accurately capture and reflect the various operational and non-power
constraints, while meeting flow and storage targets of hydro resources, and then
associate the considerations that go into the dispatch decision-making processes. The
time period approach is a way to estimate the QCC in a manner that objectively reflects
these various considerations. It must also be recognized that the time period approach
reflects historical market conditions and constraint parameters. Care must be taken to
ensure the modelling of the hydro QCC is constantly reviewed and updated as
warranted by any significant changes to those parameters to ensure the results can be
properly interpreted and applied.
In order to ensure that the modelled QCC of the footprint’s hydro fleet is properly
stated, it is anticipated that the hydro methodology proposed here would be used in
conjunction with a portfolio analysis of all RA resources for the NWPP footprint, in order
to ensure that the footprint’s RA fleet works collectively to meet the system needs.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 108 of 254
Consistent with the RA metric recommended by the Steering Committee, the time
periods that will be considered are the Summer season (June through September 15th)
and Winter season (November through March 15th).
D.1.1.1. Ten-Year Historical Period
To capture a wide range of variability around the operating conditions of storage hydro
resources, it was determined that ten years of historical data should be considered. A
ten year look back is expected to provide enough operations data to include a range of
hydrological conditions. The data should reflect associated elevation and storage
impacts on the hydro generation over a sufficiently broad range of conditions, for the
purpose of evaluating hydro QCC. If assessing firm energy capability in the future,
looking to a much longer period of time that includes critically low stream-flows would
be needed. The current model utilizes data from 2010 through 2020 and will be updated
moving one year forward each year.
D.1.1.2. Use of Capacity Critical Hours
The storage hydro capacity contribution evaluation will use the CCH identified in the
LOLE study and assessment of RA Program metrics (see Section 2.3.2).
D.1.1.3. QCC Determination
The time period approach taken to evaluate storage hydro resources evaluates the QCC
of a storage hydro resource by considering the actual generation of the resource, as well
as any additional capacity theoretically available, as identified as usable energy in the
storage reservoir. Usable storage can increase the QCC value up to the maximum
capacity of the resource. As a simple example, a hydro resource with a maximum
capacity of 125 MW (based on the elevation of the reservoir at that time) that was
generating at 75 MW during a CCH, could have a QCC on that hour of the full 125 MW
if it could be shown that there was sufficient useable energy in storage for that hour to
generate at 125 MW. On the other hand, if there was no useable energy in storage at
that resource (i.e., the resource was just passing inflows), the QCC of the resource would
be limited to the 75 MW of actual generation.
A reasonable approach to the treatment of multiple CCHs occurring on the same day is
to limit the additional capacity claimed beyond actual generation to the total usable
energy in storage on that day. As an extension of the simple example above, if the
resource was generating at 75 MW for two contiguous CCHs on a calendar day and had
an additional 50 MWh of available energy in storage, in total, over those same hours,
there would be insufficient energy in storage to run at its maximum capacity in both
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 109 of 254
hours, but the resource could be operated at an average output of 100 MW across the
two-hour period. As such, the QCC would be limited to 100 MW for the two CCHs.
When performing the evaluation, to ensure the methodology reasonably reflects the
operational flexibility of the resource, the actual historical generation of the resource in
non-CCHs is left unchanged (i.e., it cannot be assumed that generation in non-CCHs
could have been backed down to make more energy in storage available in future
CCHs).
The following methodology would be used to determine the QCC value using the time
period approach described above:
• For each day found to contain one or more CCHs, the hydro resource will be
evaluated to determine the maximum available capacity for each CCH, based on
the conditions of the storage associated with the hydro resource on that day.
• For each hydro resource, for each CCH, determine:
o Generation output during the CCH
o Useable energy in storage at the end of the CCH
o QCC for each hour, which would be the generation output plus useable
energy in storage, up to the maximum generation capability (adjusted for
reservoir elevation head as applicable), taking into account plant or unit-
specific limitations (e.g., units on a common penstock, transformer
limitations, etc.) and the resource’s EFOR.
▪ For calendar days with multiple CCHs, the QCC will be limited to the
actual generation, plus the usable energy in storage over that day
o Non-power operational constraints that limit the use of energy in storage

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 110 of 254
Table 2-19. Resource information required to apply the methodology.
Information Needed Notes
Reservoir elevation range Min and Max – this may be seasonally
adjusted
Reservoir Storage Curve Indicating energy in storage based on the
reservoir elevation
Resource Pmax vs Elevation Indicating maximum capacity of resource as
the elevation of the reservoir changes
Power as a function of discharge For the ”Discharge Method”
H/K as a function of elevation For the ”Elevation Method”
Hourly Historical Data
− Actual generation
− Starting reservoir elevation
− Ending reservoir elevation
− Any applicable resource generation
restrictions (seasonal flow restrictions,
etc.)
− Any applicable reservoir elevation
restrictions reflected as a minimum water
in storage value
− Other non-power operation constraints
limiting the use of water in storage

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 111 of 254
From the information in Table 2-19, the hourly values in Table 2-20 can be estimated for
each CCH:
Table 2-20. Hourly values that can be estimated.
Estimated Values Notes
Actual water in storage Using the elevation and storage (kcfsh) tables
Additional capacity available beyond the
actual generation Subject to elevation restrictions
Cumulative additional generation
The running total of the additional generation
claimed in each CCH for the calendar day,
used to deplete the elevation of the reservoir
to validate the feasibility of using additional
capacity in each CCH on each calendar day
Hourly QCC The sum of the actual generation plus the
additional capacity available

The hydro capacity contribution towards the RA requirement is calculated by the
resource owner as the simple average of the hourly QCC values in each CCH over the 10
seasons studied. These QCC values are averaged over each month in each season to
determine final monthly QCC values.
Figure 2-8 illustrates the application of the methodology to the Rocky Reach hydro
facility.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 112 of 254

Figure 2-8. Example application of the Storage Hydro QCC Methodology for Rocky Reach.

The Steering Committee recommended that an UCAP methodology based on forced
outage rates be applied to hydro resources to account for forced outages, consistent
with the treatment of the other dispatchable (thermal) resources. The UCAP
methodology is generally expressed as
𝑼𝑪𝑨𝑷=𝑰𝑪𝑨𝑷∗(𝟏−𝑬𝑭𝑶𝑹𝒅)
Where:
ICAP is the installed (nameplate) capacity of a thermal unit or the maximum
operational capacity if it is less than nameplate (hydro)
EFORd is the resources Equivalent Demand forced outage rate, calculated by
looking at historical outage statistics for the resource (GADS data, or
equivalent).
The UCAP ratings will be used as the maximum capacity of hydro units when applying
the NWPP Storage Hydro QCC Methodology.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 113 of 254
D.1.1.4. Treatment of Planned Outages
In addition to accounting for forced outages, the workgroup proposes that UCAP values
used in the FS workbooks be reduced for planned outages. This will ensure that QCC is
calculated correctly in hours limited by insufficient storage (occurs most often over
multiple, consecutive CCHs in the same day).
Table 2-21 and Table 2-22 below illustrate the QCC calculation over a four-hour
consecutive period using the UCAP methodology and the UCAP + planned outages
methodology.
Table 2-21. Calculating QCC using UCAP = 125MW.
Consecutive
CCHs
Historical
Generation
Historical
Storage
UCAP
(125 MW)
Draft to
maximize
Capacity
Storage
Hydro
after
draft
QCC
MW MWh MW MWh MWh MW
1 50 250 125 75 175 125
2 50 125 75 100 125
3 50 125 75 25 125
4 50 125 25 0 75
Storage empty after 25 MW draft 4-hour average 113

Table 2-22. Calculating QCC using UCAP + Planned Outages = 100 MW.
Consecutive
CCHs
Historical
Generation
Historical
Storage
UCAP +
Planned
outages
(100 MW)
Draft to
maximize
Capacity
Storage
Hydro
after
draft
QCC
MW MWh MW MWh MWh MW
1 50 250 100 50 200 100
2 50 100 50 150 100
3 50 100 50 100 100
4 50 100 50 50 100
A 25 MW planned outage decreased QCC by 13 MW 4-hour average 100

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 114 of 254
The four consecutive CCHs in Table 2-21 illustrate how the QCC is limited due to
insufficient storage. In Table 2-22, the UCAP is reduced by a 25 MW planned outage.
This reduced capacity requires less draft from storage in CCHs 1-3 to maximize the QCC
in those hours. This reduction in draft provides sufficient storage in CCH 4 to maximize
the QCC.
For FS purposes, the workgroup proposes that planned outages be included in the QCC
calculation.
D.1.1.5. Treatment of Non-Power Constraints
Each Participant is asked to review methodology and incorporate the specific non-
power constraints that are applicable to the individual projects, thus reducing the QCC
value of each plant to a level that is believed to correspond to today’s operational
capability. This is done through creating additional constraint logic in the spreadsheet
that adds today’s non-power constraint to all 10 years’ worth of evaluation.
While the addition of non-power constraints is an ‘ask’ under the methodology, it is
expected that Participants/LREs will include those non-power constraints that limit their
operational capability. Given that the QCC values of Storage Hydro transfer directly into
the Ops Program, Participants/LREs would be disadvantaged to not account for those
constraints and then be called upon to deliver capacity from those resource when it was
not available.
D.1.1.6. Treatment of Cascaded and Coordinated Hydro Systems
A Cascaded Dual Plant methodology was also developed specifically for cascaded and
coordinated hydro systems. For cascaded hydro resources on the same river systems
that are operated in a coordinated manner, when determining the QCC, the useable
energy in storage at the downstream resource could be enhanced by the operations at
the upstream resource, thereby maximizing the contribution of the combined cascade
systems. The Cascaded Dual Plant methodology does not attempt to optimize use of the
upstream storage to maximize the combined QCC, but it does allow the downstream
project to utilize the additional discharge from the upstream project. The additional
discharge from the upstream project can come in the form of spill. Spill is not a
component of the single plant model.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 115 of 254
D.2. Areas of Further Exploration
The following areas of potential further study have been identified:
D.2.1. 10 Year Period
Because the results of any time period approach will be very sensitive to water supply
conditions and associated reservoir levels, it was identified that a rolling ten-year look-
back may not capture the wide range of water conditions that could be experienced. To
address this concern, the look-back period could be extended to look further back in
time. However, since hydro operations and reservoir management has changed over
time, the older data captured may not be indicative of expected operations looking
forward, making the resulting capacity contribution results less reliable. As such,
consideration should be given to the trade-offs associated with using a larger data set.
D.2.2. Interaction with RA Program Modelling
It will be critical to understand how the hydro capacity contribution methodology fits
together with the other elements of the RA modelling effort, in order to properly
identify and address any gaps in the hydro methodology or how it might be applied.
D.2.3. Stress Case Analysis
After the completion of the non-binding program (anticipated to be three seasons) the
RA Program will undertake an analysis to understand the impact of persistent fuel
supply limitations (an energy adequacy stress case), particularly as it relates to storage
hydro, on participants ability to meet their RA program compliance metric. The "stress
case" will include both the Summer and Winter seasons, utilize exceptionally high loads
and a reduced hydro QCC resulting from water year conditions similar to 2001. The
NWPP Storage Hydro QCC Methodology may not be re-run for all storage hydro
using critical water, but an attempt will be made to understand the impact on projects
with a range of storage and flexibility. The reduction in QCC to the representative plants
will be used as a proxy for the impact to the region-wide fleet. The group will ask the PO
to make an assessment of how deficit the footprint might be in each season under these
stress scenarios. The deficit will then be allocated to 1) deficiency in CRs, 2) reliance on
imports (beyond the RA Program’s import/export assumptions), or, if no imports are
available, load curtailment. This will allow for informed discussion about the impact of
extreme tail events and the tradeoff between covering these events and being exposed
to them. As time and resources allow, a more thorough assessment of tail events could
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 116 of 254
be made by incrementally reducing the amount of hydro QCC available in the model,
increasing the load and observing the impact to the LOLE/PRM.
D.3. Variable Energy Resources
The QCC for VER resources will be determined annually for each month through the use
of an ELCC analysis. With some exceptions, the models for the ELCC study will be the
same as the model used for the year two (T-0) LOLE study. The exceptions mainly are
based on using actual historical loads instead of forecasted peak demand for the
modeled areas.
D.3.1. Effective Load-Carrying Capability Modeling
Table 2-23 shows are how certain parameters of the VER ELCC study will be handled.
Table 2-23. VER ELCC modeling parameters.
Parameter Notes
Area modeling Specific resource zones will be used in the ELCC study. The loads and
generation in each resource zone will be modeled separately.
Load modeling Handled in accordance with the LOLE study, except that loads will
not be scaled to forecast peak.
Load Forecast
Uncertainty No LFU will be taken into account.
Generator modeling
− Thermal generators – modeled existing resources with the same
parameters and assumptions as in the LOLE study.
− Storage hydro generators – modeled existing resources only with
the same parameters and assumptions as in the LOLE study.
− VERs – modeled existing and projected resources for the year
and season of interest with the same parameters and
assumptions as in the LOLE study.
− Other generation – modeled existing resources only with the
same parameters and assumptions as in the LOLE study.

Effective load-carrying capability will be determined for the VERs in the RA Program
footprint. The ELCC study will consist of analyses utilizing LOLE metrics to determine the
capacity provided by the VERs being analyzed. The LOLE benchmark metric to be used
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 117 of 254
in the ELCC accreditation study will be a one event in 10-year threshold. The ELCC of
VERs will be calculated on a monthly basis. For the ELCC study, loss-of-load events will
be tabulated during the binding season hours for determination of the 1-in-10 LOLE.
Loss-of-load events that occur outside of the binding season hours will not go into the
calculation of the capacity value of VERs.
Other generation types (non-VERs) will be removed (or added) from (to) the model to
make a determination of whether the RA Program footprint reaches the 0.1 day per year
reliability threshold. Perfect capacity will be simulated for these determinations.
D.3.1.1. Simulation Process
The PO will conduct the ELCC study by performing probabilistic simulations in a manner
that resources in the RA Program footprint will be randomly forced out of service during
each hour of the study. Each simulation accounts for a different variation of forced
outages and load uncertainty for all hours of the year, similar to the LOLE Study.
Simulations will be performed for each month of the binding season. These will be
broken down as follows:
− Summer: June, July, August, September 1-15
− Winter: November, December, January, February, March 1-15
Each historical year will be analyzed separately. The ELCC results from each year will be
averaged together for a final result.
D.3.2. Effective Load-Carrying Capability Study
Process
To determine total ELCC, an LOLE value for the benchmark system will be calculated. The
benchmark system is defined as load supplied by all conventional (coal, gas, etc.) and
storage hydro generation in the RA Program footprint. The VER of interest will be
excluded from the benchmark system. All other VER types will be included. For example,
if the wind resource type is being analyzed, only wind will be excluded from the
benchmark system.
If the resulting LOLE is greater than the 0.1 day per year threshold, “pure capacity” will
be added until the 0.1 threshold is achieved. (“pure capacity” refers to adding same
amount of capacity for every hour of the year or season without an assigned forced
outage rate.)
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 118 of 254
If LOLE is less than the 0.1 day per year threshold, “pure negative capacity” will be added
until the 0.1 threshold is achieved.
The capacity calculated is designated in Figure 2-9 as “Pure Capacity 1.”
Figure 2-9. Diagram of system without renewable resources.

Next, an LOLE value for all wind generating units will be determined, repeating the steps
described previously. The pure capacity value calculated is designated in Figure 2-10 as
“Pure Capacity 2.”

Figure 2-10. Diagram of system with renewable resources.

The difference between the results of these two steps is considered the ELCC accredited
value of the resources being studied.
𝑬𝑳𝑪𝑪 𝒐𝒇 𝑽𝑬𝑹 (𝒖𝒏𝒅𝒆𝒓 𝒔𝒕𝒖𝒅𝒚)
=𝑷𝒖𝒓𝒆 𝒄𝒂𝒑𝒂𝒄𝒊𝒕𝒚 𝟏−𝑷𝒖𝒓𝒆 𝒄𝒂𝒑𝒂𝒄𝒊𝒕𝒚 𝟐

These processes are repeated to determine QCC for each year that is studied. This
process is repeated for Summer and Winter separately.
D.3.2.1. Determination of VER zones
The ELCC study will determine the amount of capacity provided by all VERs (of the
specified type: e.g., wind) analyzed in the RA Program footprint. This overall capacity
Base System
Pure
Capacity 1
Base System Pure
Capacity 2

Wind
Generation
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 119 of 254
contribution value must be allocated to individual VERs to enable Participants to
properly claim their resources’ QCC value.
The FS Program will determine and demarcate geographic VER zones for each VER
resource type and assign existing VERs to a zone. Effective load-carrying capability
studies will be performed for each VER zone (and VER type), calculating a total capacity
value of the resource of interest in that zone. The capacity calculated for each zone will
be allocated to VERs of that type in that zone on a pro-rata basis.
To ensure that over-accreditation of VERs does not occur, the PO will conduct an ELCC
study of the entire RA Program and calculate a total capacity value for all VERs (of each
type) in the RA Program footprint. After each VER zone capacity total (for each VER
type) has been determined, the sum of the VER zone totals will be compared to the
footprint total. If the sum of the zones is greater than the footprint total, all VER zone
totals will be scaled down until the totals match the footprint total. Table 2-24 provides
an example of the calculations to determine total VER (in this case: wind) capacity.
Table 2-24. ELCC Study of RA Program footprint to calculate total wind capacity.
A study of four wind zones reveals the following capacity values for
wind in each zone:
Zone 1 Zone 2 Zone 3 Zone 4 Total
1,000 MW 800 MW 700 MW 1,000 MW 3,500 MW
A study of the region reveals the following capacity value for the
region’s wind:
Regional wind = 3,200 MW
The zones will be recalculated as follows:
Zone 1 Zone 2 Zone 3 Zone 4 Total
1,000 *
(3,200/3,500)
800 *
(3,200/3,500)
700 *
(3,200/3,500)
1,000 *
(3,200/3,500)
914 MW 732 MW 640 MW 914 MW 3,200 MW

At this time, the FS Program has not made a final determination of VER zones for any
VER resource types.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 120 of 254
D.3.3. Determination of ELCC for Future VER
Resources
It is understood that as VERs are added to a system, the capacity value provided by all
similar VERs as a function of the nameplate value of those resources will decrease. It
therefore becomes important for Participants to have an understanding of how VER
QCC values may change over time as the penetration of VERs increases.
For each VER zone, after the QCC of all existing and near-term planned VERs have been
calculated and allocated, additional ELCC studies will be performed to account for future
VERs (of each type) in each zone. It is proposed to study incremental additions of wind
and solar resources in each wind and solar zone of 2,000 MW, 4,000 MW and 6,000
MW19. These additional wind and solar resource amounts will be created by scaling up
the number of wind turbines (nameplate capacity) or solar photovoltaic in each zone.
The PO will provide an ELCC curve that can be used to determine future capacity values
for new resources dependent upon the penetration of resources in that zone.
D.3.4. Treatment of other classes of VERs in the ELCC
analysis
One complexity of performing ELCC analyses for multiple classes of VERs is the
complementary/antagonistic impact that VERs may have on each other. For example, if
many wind resources are in the base case for a study on solar resources, the solar
resources could be impacted negatively. However, if no wind resources are included in
the base case, the solar resources may receive more capacity credit than they should.
There could be a positive impact if the wind resources are found to be providing
capacity during hours when solar resources may not be able to provide capacity.
However, if there is an amount of wind that is so great that it shifts the capacity need for
solar resources into an hour where sunlight is not plentiful, then those solar resources
may be negatively impacted. For consistency, the FS Program will include all VERs not
being analyzed in the base case when studying the resources of interest. The wind ELCC
study will include all solar and run-of-river hydro resources. The solar ELCC study will
include all wind and run-of-river hydro resources. The run-of-river hydro study will
include all wind and solar resources.
19 It may not be necessary to study incremental amounts of run-of-river hydro resources.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 121 of 254
D.4. Short-Term Storage
Short-term ESRs will have their capacity value determined by the value the resource is
able to produce during its capability test for the required duration of the test. Short-
term ESRs will be modeled in the manner of a thermal resource whose maximum power
capability is equal to the capacity value. If an outage rate history can be obtained for
such resources, it will be utilized.
To determine the duration requirement for short-term ESR (Table 2-25) a review of the
top 5% of CCHs was undertaken for the previous 10 years of Summer binding seasons
and the previous 10 years of Winter binding seasons. The number of CCHs in a day was
tracked. The total weighting of each value was multiplied by the % of days that had that
value. The weighting methodology resulted in a duration of 5 hours for the Summer
binding season ESRs and 4.7 hours for the Winter binding season ESRs.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 122 of 254
Table 2-25. Duration requirement for short-term storage.
Duration of CCH in Day % of CCH Days Weight
Su
m
m
e
r

(
4

h
o
u
r

mi
n
i
m
u
m
)

4 61.00% 2.44
5 13.00% 0.65
6 10.00% 0.6
7 7.00% 0.49
8 5.00% 0.4
Total Weighting (Summer) 100.00% 4.96
Wi
n
t
e
r

(
4

h
o
u
r

m
i
n
i
m
u
m
)

4 74.00% 2.96
5 9.00% 0.45
6 6.00% 0.36
7 4.00% 0.28
8 3.00% 0.24
9 2.00% 0.18
10 1.00% 0.1
11 1.00% 0.11
Total Weighting (Winter) 100.00% 4.68

D.5. Thermal Units
The QCC for thermal units will be calculated with a performance-based methodology.
The methodology will calculate UCAP using NERC GADS (or equivalent) data and a
seasonal EFOF equation using the term “EFOF (CCH)”.
Participants will provide their NERC GADS (or equivalent) data to the PO in the annual
data request to the PO. The PO will calculate QCC values for all thermal resources using
the following guidelines:
𝑬𝑭𝑶𝑭(𝑪𝑪𝑯)=𝟏− ∑𝑭𝑶𝑯𝒄𝒄𝒉+𝑬𝑭𝑫𝑯𝒄𝒄𝒉
𝒕𝒐𝒕𝒂𝒍𝑪𝑪𝑯
∗𝟏𝟎𝟎%
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 123 of 254
Where:
FOHcch is Forced Outage hours occurring on CCHs,
EFDHcch is Equivalent forced derating hours occurring on capacity critical hours,
and
Total CCH is total number of CCHs for the timeframe of interest.

Definitions of FOH and EFDH can be found in Table 2-26.
Table 2-26. Definitions of FOH and EFDH.
Definitions
FOH Sum of all CCH experienced during Forced Outages (U1, U2, and U3) +
Startup Failures.
EFDH
Each forced derating (D1, D2, and D3) transformed into equivalent full
outage hour(s). This is calculated by multiplying the actual duration of
the derating (hours) by the size of the reduction (MW) and dividing by
the net maximum capacity. These equivalent hour(s) are then summed
by CCH.

𝐷𝑒𝑟𝑎𝑡𝑖𝑛𝑔 𝐻𝑜𝑢𝑟𝑠∗𝑆𝑖𝑧𝑒 𝑜𝑓 𝑅𝑒𝑑𝑢𝑐𝑡𝑖𝑜𝑛
𝑁𝑒𝑡 𝑀𝑎𝑥𝑖𝑚𝑢𝑚 𝐶𝑎𝑝𝑎𝑐𝑖𝑡𝑦

• Perform calculation for each resource seasonally and for each historical year. QCC
will be assigned to each resource for the entire binding season.
• Six years of data will be used for the calculation. The worst performing year will
be removed from the calculations, allowing for a five-year average.
• Only forced outages or derates occurring during CCHs will be used to calculate
QCC. Outages during hours that are not deemed to be capacity critical will not
negatively impact QCC.
• All years (of the 5 years) to have equal weighting.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 124 of 254
• Outside of Management Control outages as reported under NERC GADS
Appendix K20 (or equivalent) will be excluded from the calculation.
• For Participants relying on resource specific transactions external to the FS
Program, those resources will follow the same UCAP structure for thermal
resources and the Participant will be responsible to make sure the information is
provided to the PO.
• Each event will need to be broken out by hour. If the NERC GADS (or equivalent)
data is reported in minutes, then the hour that contains the outage will need to
be equalized to account for the minutes. For example: if an outage starts on
6/1/2020 at 4:25, then the hour duration for that hour will be less than 1 since the
outage does not start at the top of the hour. The total hours for 6/1/2020 on
hour beginning 4:00 would be 0.583 ([60 Minutes – 25 minutes] / 60 minutes in
an hour).
• Diversity of time zones will need to be considered.
• When comparing the event hours to the CCH hour ending identification should
be consistent.

D.5.1. Methodology for units that do not have at least
6 years of outage data
For units that have been in service for at least six years but provide only five years of
data, all five years will be included in the analysis and the worst performing year will not
be excluded.
For units that have been in service for at least six years but provide less than five years
of outage data, the outage data provided will be used to determine the QCC. Years with
no outage data provided will be treated as years with zero QCC in the overall
calculation.
For new units that have been in service less than six years, class average data will be
used at the discretion of the PO.
20 Appendix K of NERC GADS:
https://www.nerc.com/pa/RAPA/gads/DataReportingInstructions/Appendix_K_Outside_Management_Cont
rol_2021_DRI.pdf
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 125 of 254
D.5.2. Methodology for units that do not report NERC
GADS (or Equivalent) data
Resources that have been in services for more than six years but have not had their
NERC GADS (or equivalent) data provided to the PO will not meet qualification and
registration requirements of the FS Program.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 126 of 254
SECTION 2: APPENDIX E -
TRANSMISSION MODELING
CONSIDERATIONS
The RA Program has worked with the NWPP and Participant TSPs to develop a set of
LRZs that depict the presence of transmission constraints that are known transmission
congestion paths or points in the NWPP area. These LRZ boundaries have been
determined by review of historical usage of the transmission system and the resulting
constraints that have been identified. The LRZs have been set as described in Table 2-27.
Table 2-27. Transmission service-related LRZs.
Zone
designation General description Participants
located in zone
Transmission paths
identified as constraints
to imports and exports
Zone 1 British Columbia BC Hydro - Powerex Path 3
Zone 2 Western Washington,
Northwest Oregon
PGE, Tacoma, EWEB,
Seattle, PacifiCorp,
BPA
Path 4, Path 5, Dixonville
Zone 3
Eastern Washington
and Oregon,
Southwest Oregon,
Northern Idaho
PacifiCorp, BPA,
Puget Sound,
Douglas, Chelan,
Avista, Grant
Path 3, Path 4, Path 5,
Dixonville, Path 66, Path 76
Path 14/75, Path 8
Zone 4 Montana Northwestern, BPA Path 8, Path 18, Path 80
Zone 5 Southern Idaho Idaho Power, BPA Path 14/75, Path 16, Path
18, Path 19, Path 20
Zone 6 Wyoming, Utah PacifiCorp, BPA Path 19, Path 20, Path 29,
Path 80
Zone 7 Nevada Nevada Energy, BPA Path 16, Path 29, Path 76
Zone 8 Colorado PSCo
Various paths separating
eastern Colorado from the
rest of the NWPP footprint
Zone 9 California TID, BANC
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 127 of 254

The FS Program will determine Participant usage of the transmission system through
firm reservations provided by Participants in their FS portfolios. A complete listing of
firm reservations will be gathered by the PO. Additionally, the PO will determine the
transmission usage by Participant submitted resources that have not demonstrated firm
transmission in the FS window21.
Each transaction will be analyzed by simulating a 1 MW transfer using the point of
receipt and point of delivery. For each reservation, transmission distribution factors
(TDFs) will be captured on all transmission paths identified as constraints to imports and
exports. For each reservation, the total reservation amount (in MW) will be multiplied by
the TDF for each constraint to capture the MW flow on the constraint. Flows will be
captured in both directions to account for counterflows. An example is shown in Table
2-28.
Table 2-28. Reservation – 100 MW from Northwestern to Portland General Electric.
1 MW transfer is simulated from NWMT → PGE
The following TDFs are captured:
Path 8 = 0.5
Path 4 = 0.5
Path 18 = 0.25
Path 14/75 = 0.2
Path 5 = 0.3
The following flows are added to the paths:
Path 8 = 50 MW
Path 4 = 50 MW
Path 18 = 25 MW
Path 14/75= 20 MW
Path 5 = 30 MW

Once the total reserved capacity on all paths has been determined, this information will
be used by the PO in the determination of whether LRZs have sufficient import
capability to maintain the regional PRM value or whether the LRZ will be considered a
transmission constrained zone.
21 The amount of firm transmission service required for resources to be shown in the Forward Showing
window is being determined and will be available in the ”Transmission Memorandum.”
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 128 of 254
E.1. Determination of a Transmission
Constrained Zone
To determine whether an LRZ is transmission constrained, it must be determined that
the zone needs a specified amount of transmission import capability in the LOLE
analysis for the zone to meet the reliability threshold of 1 event-day in 10 years. In order
to make such a determination, the LOLE analysis for each LRZ will analyze the ability of
the resources located within the LRZ to serve the load within the LRZ while allowing no
imports. If an LRZ is determined to be capacity adequate (e.g., can meet the 1-in-10
LOLE metric) then the LRZ is not transmission constrained because imports are not
required to meet the 1-in-10 LOLE metric for the LRZ.
If an LRZ is determined to be capacity deficient in meeting the 1-in-10 LOLE, the
capacity deficiency will be quantified by determining the amount of capacity that must
be added to bring the zone up to the 1-in-10 LOLE metric. Then, the PO will compare
this capacity deficiency to the import capability of the LRZ to determine if adequate
import capability into the LRZ exists that will allow the LRZ to utilize capacity outside the
LRZ. If sufficient import capability is found to exist, the LRZ may maintain the regional
PRM requirement. If insufficient import capability is found to exist, and unless additional
transmission capacity is able to be obtained or demonstrated, the PO will determine a
new PRM value for the transmission constrained LRZ. The new PRM value will take into
account the contracted import capability (i.e., transmission reservations) the LRZ has to
import capacity.
For example, if it is seen that a certain LRZ needs 4,000 MW of firm import capability to
meet the 1-in-10 LOLE, a review of transmission reservations from the resources that
have firm service submitted by the zone Participants (that are located outside the zone)
to the zone will be performed. If there are not enough transmission service reservations
to account for the needed import capability, the LRZ is potentially transmission
constrained. Options to remedy this situation can be either for additional transmission
capacity to be obtained or to calculate a higher PRM for the zone.
The PO will share the results of this analysis with the TSPs of the FS Program. Each TSP,
at their own option, will take the transfer capability limitations of the paths and run
additional simulations to determine transfers across their own internal congested path(s)
if they have any.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 129 of 254
SECTION 2: APPENDIX F - PORTFOLIO
CONSTRUCTION DETAILS AND EXAMPLES
As stated in Section 2.6, a Participant’s FS capacity requirement, the QCCs of their resources
and contracts, and their FS portfolio compliance will be calculated and reported22 monthly.
Table 2-29, Table 2-30, Table 2-31 provide examples for a Participant’s resources QCC ledger,
net contract QCC ledger, and total RA transfers.
Table 2-29. Example of a Participant’s resource QCC ledger.
Resource Registration
Asset Owner/Operator: PARTICIPANT A
ID Resource
Name
Resource
Type
Resource
Subtype
Nameplate
Capacity
Forced
Outage
Rate
Accred-
itation
Start
Month
Year
End
Month
Year
QCC
/
UCAP
1 Hydro 1 Hydro Run-of-
river
600 0.4 2022-11 2022-11 240
1 Hydro 1 Hydro Run-of-
river
600 0.4 2022-12 2022-12 240
1 Hydro 1 Hydro Run-of-
river
600 0.4 2023-01 2023-01 240
1 Hydro 1 Hydro Run-of-
river
600 0.4 2023-02 2023-02 240
1 Hydro 1 Hydro Run-of-
river
600 0.4 2023-03 2023-03 240
2 Hydro 2 Hydro Storage 1200 0.03 2022-11 2022-11 950
2 Hydro 2 Hydro Storage 1200 0.03 2022-12 2022-12 1050
2 Hydro 2 Hydro Storage 1200 0.03 2023-01 2023-01 1000
2 Hydro 2 Hydro Storage 1200 0.03 2023-02 2023-02 980
2 Hydro 2 Hydro Storage 1200 0.03 2023-03 2023-03 1000
3 Thermal
3
Thermal Natural
Gas
700 0.05 0.95 2022-11 2022-11 665
3 Thermal
3
Thermal Natural
Gas
700 0.05 0.95 2022-12 2022-12 665
3 Thermal
3
Thermal Natural
Gas
700 0.05 0.95 2023-01 2023-01 665
3 Thermal
3
Thermal Natural
Gas
700 0.05 0.95 2023-02 2023-02 665
3 Thermal
3
Thermal Natural
Gas
700 0.05 0.95 2023-03 2023-03 665
4 Wind 4 Wind 70 0.15 2022-11 2022-11 10.5
4 Wind 4 Wind 70 0.15 2022-12 2022-12 10.5
22 QCC will be calculated for thermal resources on a seasonal basis but will be reported monthly – each month of
the season will have an identical QCC unless other factors such as planned maintenance impact this value.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 130 of 254
Resource Registration
4 Wind 4 Wind 70 0.15 2023-01 2023-01 10.5
4 Wind 4 Wind 70 0.15 2023-02 2023-02 10.5
4 Wind 4 Wind 70 0.15 2023-03 2023-03 10.5
5 Hydro 5 Hydro Storage 400 0.06 2022-11 2022-11 300
5 Hydro 5 Hydro Storage 400 0.06 2022-12 2022-12 360
5 Hydro 5 Hydro Storage 400 0.06 2023-01 2023-01 320
5 Hydro 5 Hydro Storage 400 0.06 2023-02 2023-02 350
5 Hydro 5 Hydro Storage 400 0.06 2023-03 2023-03 350

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 131 of 254
Table 2-30. Example of a Participant’s net contract QCC ledger.
Contractual Obligations Against Fleet
FROM
ENTITY
TO
ENTITY
PURCHASE
/ SALE
RESOURCE
NAME
%
SHARE
WITHIN
FOOTPRINT
START
MONTH
YEAR
END
MONTH
YEAR
AMOUNT
FORCED
OUTAGE
CLAIMANT
ENTITY A ENTITY B SALE SYSTEM YES 2022-11 2022-11 -200 ENTITY A
ENTITY A ENTITY B SALE SYSTEM YES 2022-12 2022-12 -200 ENTITY A
ENTITY A ENTITY B SALE SYSTEM YES 2023-01 2023-01 -200 ENTITY A
ENTITY A ENTITY B SALE SYSTEM YES 2023-02 2023-02 -200 ENTITY A
ENTITY A ENTITY B SALE SYSTEM YES 2023-03 2023-03 -200 ENTITY A
ENTITY A ENTITY C SALE HYDRO 2 0.4 YES 2022-11 2022-11 -380 ENTITY C
ENTITY A ENTITY C SALE HYDRO 2 0.4 YES 2022-12 2022-12 -420 ENTITY C
ENTITY A ENTITY C SALE HYDRO 2 0.4 YES 2023-01 2023-01 -400 ENTITY C
ENTITY A ENTITY C SALE HYDRO 2 0.4 YES 2023-02 2023-02 -392 ENTITY C
ENTITY A ENTITY C SALE HYDRO 2 0.4 YES 2023-03 2023-03 -400 ENTITY C
ENTITY A ENTITY D SALE SYSTEM YES 2023-01 2023-01 -150 ENTITY A
ENTITY A ENTITY D SALE SYSTEM YES 2022-12 2022-12 -700 ENTITY A
ENTITY A ENTITY E SALE SYSTEM YES 2023-02 2023-02 -75 ENTITY A
ENTITY A ENTITY E SALE SYSTEM YES 2023-03 2023-03 -75 ENTITY A
ENTITY A ENTITY F SALE SYSTEM YES 2022-11 2022-11 -200 ENTITY A
ENTITY A ENTITY F SALE SYSTEM YES 2023-03 2023-03 -200 ENTITY A
ENTITY A CAISO SALE SYSTEM NO 2023-03 2023-03 -150 ENTITY A
ENTITY A ENTITY G SALE WIND 4 YES 2023-03 2023-03 -5 ENTITY A
ENTITY S ENTITY A PURCHASE SYSTEM YES 2022-11 2022-11 50 ENTITY S
ENTITY Z ENTITY A PURCHASE SYSTEM YES 2022-11 2022-11 500 ENTITY Z
ENTITY A ENTITY Y SALE SYSTEM YES 2022-11 2022-11 -800 ENTITY A

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 132 of 254
Table 2-31. Example of a Participant’s Total RA transfers.
RA Transfers
FROM
ENTITY TO ENTITY TRANSACTION
TYPE
PURCHASE/S
ALE
START
MONTH
YEAR
END
MONTH
YEAR
AMOU
NT
ENTITY A ENTITY B RA TRANSFER SALE 2022-11 2022-11 25
ENTITY A ENTITY B RA TRANSFER SALE 2022-12 2022-12 10
ENTITY A ENTITY B RA TRANSFER SALE 2023-01 2023-01 10
ENTITY A ENTITY B RA TRANSFER SALE 2023-02 2023-02 10
ENTITY A ENTITY B RA TRANSFER SALE 2023-03 2023-03 20

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 133 of 254
SECTION 2: APPENDIX G – INDICATIVE
ANNUAL ASSESSMENT RESULTS
The process for performing Annual Assessments is given in Appendix A-F.
G.1. Disclaimer
This Appendix G relays indicative results of the Annual Assessments that were performed to
determine a “proof-of-concept” of the Program Design. These results are based on input data
provided by the Participants during the detailed Program design. The input data provided by
the Participants was not validated by the Program Developer as these simulations were not
intended to provide any justification for a business case to the Participants. The results do not
include any potential impacts from the Transmission and Deliverability policy which was still
in development when these simulations were performed. These results are very likely to be
impacted by ongoing review and refinement of design parameters (in upcoming project
phases and beyond). Figures and ranges are provided only for context on the program design
and as continued support for the value of a regional RA Program – they should not be utilized
without accompanying design information and/or appropriate understanding of their
approximate nature at this time. .
G.2. Planning Reserve Margin
The process for determining the PRM is detailed in Appendix B.
G.2.1. Resources Used In Analysis
The dispatchable resources submitted by Program Participants for review in the indicative
analyses are shown below in Table 2-32. The values for thermal resources (natural gas, coal,
etc.) are the nameplate values. Approximate storage hydro QCC values were determined by
the Hydro QCC Methodology, where the January values represent the Winter MWs, and the
August values represent the Summer values. Note that these hydro QCC values are shown as
approximate, as there was no validation of the application of the methodology during this
simulation.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 134 of 254
Table 2-32. Participant dispatchable resources.
Modeled Resources by
Fuel Type Summer MW Winter MW
Storage Hydro – approx.
QCC Value 38,897 42,271
Natural Gas 22,058 23,085
Coal 10,377 10,407
Demand Response 1,944 547
Nuclear 1,181 1,163
Geothermal 502 502
Pumped Storage 324 324
Petroleum 202 223
Biomass 86 87
Other 173 173
Total 75,744 78,781

Variable Energy Resources included in the analysis are listed below in Table 2-33. These
values are nameplate capacity values.
Table 2-33. Participant VER.
Modeled Fuel
Type Summer MW Winter MW
Run-of-river hydro
(NP) 4,766 4,766
Solar (NP) 7,346 7,346
Wind (NP) 16,432 16,432

Firm imports into the Program footprint are given below in Table 2-34.
Table 2-34. Firm transactions.
Modeled Imports Summer MW Winter MW
Firm Imports 717 717

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 135 of 254
G.2.2. Demand values used in analysis
Load and demand values as submitted by Program Participants are listed below in Table 2-35.
These values reflect a total summation of the individual peaks of Program Participants. These
values do not represent the CP of the Program. These values do not represent the loads of
any non-Participants in the Program. These values were grossed up to include the
approximation of transmission losses (3% of peak demand).
Table 2-35. Participant Demand.
Modeled Demand Summer
(MW) Winter (MW)
2023 Peak Demand – summation of all individual Participants
peaks (NCP) grossed up to include 3% transmission losses 61,351 60,635
Exports – includes a) Firm exports to non-Participants
embedded in NWPP footprint and b) Regional Interchange (not
including firm imports and not including interchange with
embedded non-Participants)
4,936 4,680
Total – Demand (NCP) 66,286 65,316

G.2.3. Loss of Load Expectation Analysis
As detailed in Appendix B, LOLE probabilistic simulations were performed. Notable items on
the LOLE simulations are listed below (see appendix B for additional detail on the modeling
design).
• Simulations performed on ten (10) years of historical weather years (2011-2020).
• Probabilistic simulations included:
o Variable forced outages of thermal generation
▪ Notably, variable forced outages of storage hydro generation was
not performed as average forced outage rates were included in
the modeled value for that generation type.
o Probability weighted load forecast uncertainty which varies load levels
(above and below forecasts). 2023 forecasts were modeled as the 50th
percentile of occurrence
o VER generation based on the year of study (2023)
• No planned or maintenance outages were included during the Summer or
Winter seasons in the simulations
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 136 of 254
• Contingency Reserves maintained during simulations (6% of RA Program
Demand)
• No transmission constraints between zones modeled
• Only LOLE on binding seasons were considered when determining LOLE for each
season
G.2.4. PRM calculation
Loss of load expectation simulations were performed to determine loss of load metrics. If the
LOLE value was less than the 1-in-10 metric, the inputs were adjusted to attain the required
metric. Once the 1-in-10 metric was achieved, the PRM was calculated. The capacity values of
the resources used in the simulations were determined based on the following procedures:
• Thermal generation – the nameplate value of thermal generation capacity was replaced
with the QCC value of thermal generation. QCC values were determined in accordance
with Appendix D.
• VER generation – the nameplate value of VER capacity was replaced with a proxy ELCC
value.
• Storage hydro – storage hydro values as modeled in the LOLE study at their QCC
values are used in the PRM calculation.
• Energy storage and Demand Response resources – ICAP values
• Pure capacity – adjustments to capacity to reach 1-in-10 metric for each binding
season
After capacity adjustments were made, the PRM was calculated using the following equation
𝑷𝑹𝑴 (𝑼𝑪𝑨𝑷) (%)= 𝑪𝒂𝒑𝒂𝒄𝒊𝒕𝒚 (@𝟏−𝒊𝒏−𝟏𝟎)−𝑫𝒆𝒎𝒂𝒏𝒅
𝑫𝒆𝒎𝒂𝒏𝒅∗𝟏𝟎𝟎

The RA Program design calls for the PRM to be based on a non-coincident peak (NCP); this
will facilitate Participant comparison to their current metrics. For comparative purposes to
other RA Programs where PRMs are often applied to coincident peaks (CP), a CP demand for
the RA Program footprint was calculated for each season from the LOLE studies. A CP PRM is
provided for informational purposes only.
The ranges of results for the Summer season are shown below in Table 2-36. These results do
not include any adjustment for transmission or deliverability policy which is still in
development.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 137 of 254
Table 2-36. Summer UCAP PRM.
Summer Demand UCAP PRM
@1-in-10
2023 (NCP) 66,286 9-15%
2023 (CP – not a
Program metric) 63,744 12.5-18.5%

The ranges of results for the Winter season are shown below in Table 2-37. These results do
not include any adjustment for transmission or deliverability policy which is still in
development.
Table 2-37. Winter UCAP PRM.
Winter Demand UCAP PRM
@1-in-10
2023 (NCP) 65,316 13-19%
2023 (CP – not a
Program metric) 63,000 17-24%

G.3. QCC of Thermal and Storage Hydro
Resources
The process for the determination of QCC of Program Resources is discussed in Appendix D.
The thermal and storage hydro indicative “proof-of-concept” QCC results are discussed in the
following sections.
G.3.1. Thermal Resources
QCC for thermal resources is based on historical performance during CCH as detailed in
Appendix C. GADS data was requested from Program Participants for their thermal resources.
Data provided from Participants included:
• Total thermal generation submitted – 34,579 MW
o Thermal generation for which GADS data was provided – 27,175 MW
o Thermal generation for which no data provided – 7,404 MW

For the thermal generation that had GADS data submitted, the QCC (via the EFOFCCH metric)
was calculated. The ranges of results are shown in Table 2-38.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 138 of 254
Table 2-38. Thermal Resource QCC.
Season System weighted
UCAP
Summer 94-99%
Winter 94-99%

G.3.2. Storage Hydro
QCC for storage hydro resources is resource specific and is handled in accordance with the
Hydro QCC Methodology detailed in Appendix D. The ranges of results are shown in Table
2-39 on a monthly basis.

Table 2-39. Storage Hydro QCC.
Month Nameplate QCC %
1 49,226 83-89%
2 49,226 80-86%
3 49,226 87-92%
4 49,226 89-94%
5 49,226 81-87%
6 49,226 76-82%
7 49,226 76-82%
8 49,226 76-82%
9 49,226 74-79%
10 49,226 81-87%
11 49,226 78-84%
12 49,226 80-86%

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 139 of 254

NWPP Resource Adequacy
Program Detailed Design

Operational Design

JUNE 2021

Prepared in collaboration with the Southwest Power Pool, as Program Developer

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 140 of 254
SECTION 3. OPERATIONAL DESIGN: TABLE
OF CONTENTS
Introduction ........................................................................................................................................................... 144
Overview of Operational Design ...................................................................................................... 144
Ops Program Anticipated Benefits .......................................................................................... 144
Binding Seasons of Ops Program ............................................................................................ 145
Design Principles for the Ops Program ................................................................................. 145
Ops Program Design For Go Live .................................................................................................................. 148
Ops Program Timeline .......................................................................................................................... 148
Sharing Requirement Calculation ..................................................................................................... 149
Sharing Calculation ....................................................................................................................... 150
Forward Showing Capacity Requirement (P50+PRM) ..................................................... 153
Forced Outages .............................................................................................................................. 153
Maintenance Outages.................................................................................................................. 155
Transmission Outages ................................................................................................................. 156
Variable Energy Resources Over Performance and Under Performance .................. 156
Run-of-River Hydro Over Performance and Under Performance ................................ 156
Load Forecast .................................................................................................................................. 157
Uncertainty....................................................................................................................................... 157
Safety Margin ............................................................................................................................... 158
Contingency Reserves ............................................................................................................... 158
Holdback Requirement Calculation ................................................................................................. 159
Prescheduling Practices ............................................................................................................... 159
Sharing Event .................................................................................................................................. 159
Holdback Requirement................................................................................................................ 160
RA Transfers ..................................................................................................................................... 162
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 141 of 254
Bilateral Exchange of Holdback Requirement ..................................................................... 165
Release of Capacity ............................................................................................................................... 166
Day-Ahead Release of Capacity ............................................................................................... 166
Multi-Day Ahead Assessment ................................................................................................... 167
Multi-Day Ahead Release of Capacity ................................................................................... 168
Energy Deployment ............................................................................................................................... 169
Frequency of Data Submission on Operating Day ............................................................ 169
Energy Deployment Calculation ............................................................................................... 169
Tagging Energy Deployment .................................................................................................... 170
Centroid Options ........................................................................................................................... 173
Scheduling Deadline .................................................................................................................... 174
Bilateral Exchange of Energy Deployment ........................................................................... 175
Transmission Service ............................................................................................................................. 175
Securing Transmission for Delivery to Load ........................................................................ 175
Firmness of Transmission Service Requirements ............................................................... 176
Securing Transmission Service .................................................................................................. 176
Role of PO with Respect to Transmission Service ............................................................. 177
Deliverability Assessment & Path De-Rates ................................................................................. 177
Settlements ............................................................................................................................................... 178
Energy Deployment and Holdback Settlement .................................................................. 178
Transmission Service .................................................................................................................... 181
Interaction of Ops Program and EIM / EDAM ........................................................................... 181
Failure to Deliver Energy Deployment ......................................................................................... 181
Notification of Failure to Deliver Energy Deployment .................................................. 181
Assessing & Waiving Penalties for Delivery Failure ........................................................ 182
Delivery Failure Review Committee ...................................................................................... 182
Load Shedding Responsibility ................................................................................................ 183
Penalty for Delivery Failure ...................................................................................................... 183
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 142 of 254
Data Submission Requirements for Ops Program ................................................................... 185
Multi-Day Ahead Data Submission ...................................................................................... 185
Operating Day Data Submission ........................................................................................... 186
Data Submission Errors and Validation .............................................................................. 186
After Fact Data Submission ..................................................................................................... 186
Notification Process ............................................................................................................................ 186
Emergency Procedure ........................................................................................................................ 187
Review of Design Elements .............................................................................................................................. 188
Review of Design Elements After First Season .......................................................................... 188
Review of Design Elements for Future Consideration ............................................................ 189
Multi-Stage Sharing Calculation ............................................................................................ 189
Seasonal Look Ahead Assessment of Sharing Events .................................................... 190
Monitoring the Health of the RA Program ........................................................................ 191
Optimizing Holdback Requirement ...................................................................................... 191
Settlement of Optimized Holdback Requirement ........................................................... 192
Capacity Ratio .............................................................................................................................. 192
Section 3: Appendix A – Processes & Procedures ................................................................................... 194
A.1. Summary of Processes and Procedures the PO Will Develop & Maintain ....................... 194
A.2. Summary of Requirements for RA Participants .......................................................................... 194

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 143 of 254
INTRODUCTION
Overview of Operational Design
The Northwest Power Pool (NWPP) Resource Adequacy (RA) Program – Operational
Design, also referred to as the Operational Program (Ops Program), is the operational
portion of the RA Program. In the Ops Program, the Program Operator (PO) monitors
the RA of Participants, forecasted load, uncertainty, and reserve requirements, along
with forced outages and Variable Energy Resource (VER) performance, to determine
when a Participant may have insufficient capacity to cover the projected demand. When
a Participant is forecasted to be deficient, the PO will initiate a Sharing Event and call on
other Participants that have a surplus to hold back capacity (via a Holdback
Requirement) and deliver energy (via an Energy Deployment) to the deficient
Participant(s). The Forward Showing (FS) Program, the RA forecast counterpart of the
Ops Program, will determine the baseline values for the components of the Sharing
Calculation [e.g., P50+Planning Reserve Margin (PRM), Forced Outage, etc.] and the Ops
Program will determine real-time differences from these values to initiate a qualifying
Sharing Event.
The Ops Program is implemented through iteratively (see Section 3.2) applying a
Sharing Calculation (see Section 3.3) beginning with a Multi-Day Ahead Assessment (see
Section 3.5), identification of Sharing Events with a Holdback Requirement on the
preschedule day (see Section 3.4), and Energy Deployments on the Operating Day [(OD),
see Section 3.6]. The Sharing Calculation is performed using Participant provided data
updated on at least a daily basis for Multi-Day Ahead Assessment through the
preschedule day for identification of Sharing Events and the data is updated hourly for
the OD for Energy Deployments (see Section 3.12).
Ops Program Anticipated Benefits
The Ops Program facilitates access to the diversity of resources across the region of
Participants. For example, during times when VERs are performing above their
accredited levels or Participants are experiencing a low level of forced generation
outages, that additional capacity may be made available to deficient Participants by the
Ops Program during times of generation shortfall. Additionally, the Ops Program will
allow Participants to maximize the benefit of the load diversity across the region during
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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periods of which one Participant is peaking and another Participant is realizing lower
load levels. The Ops Program allows Participants to collectively manage periods of risk
of capacity shortfall. The Ops Program reduces the uncertainty risk for each Participant
of the NWPP RA Program through sharing available capacity.
Binding Seasons of Ops Program
The Ops Program will be operated by the PO during the binding seasons, as defined by
the FS Program. Table 3-1 includes the proposed duration of the binding Winter and
Summer seasons. The Ops Program will initially be operated according to this schedule.
After the inception of the Ops Program, the PO may conduct analysis to evaluate
whether changes to the binding seasons are appropriate. The Winter and Summer
seasons of this program will be binding for Participants who are engaged in the
program. The Spring and Fall season will be conducted in a similar manner, but this will
be advisory only (i.e., penalties will not be assessed).
Table 3-1. Compliance Seasons.
Season Binding/Advisory Duration
Winter Binding November 1– March 15
Summer Binding June 1– September 15
Spring Advisory March 16 – May 31
Fall Advisory September 16-October 31

Design Principles for the Ops Program
The Ops Program applied the following design principles to guide in making
determinations when presented options for how to construct the Ops Program.
• The Ops Program will be a capacity program not an energy program.
• The Ops Program will perform assessments for short-term horizons that will
identify opportunities to use regional diversity in demand and supply.
o The methodology will determine when a Participant may access the
Program.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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o The methodology will determine when a Participant will be obligated to
provide capacity support to other Participants that are deficient.
• The design should be simple and cost-effective. This should be considered in
determining:
o Tools of PO.
o Data exchange between Participants and PO.
o Calculations performed by PO.
o Validations performed by PO.
o Communication between Participants and PO.
o Settlements.
o Tools required by Participants.
• The Ops Program should provide equitable benefits for all Participants.
• The Ops Program should maintain a healthy balance for all Participants both
accessing and providing capacity to the Program.
• Ensure short-term sharing commitments have appropriate transmission service
with low risk of curtailments in order to maximize reliability.
• Ensure that Balancing Authority Areas (BAAs) and Load Serving Entities (LSEs) and
Load Responsible Entities (LREs) can continue to operate safely, efficiently, and
reliably.
While designing the Ops Program, several design elements were set at lower priority.
These design elements are deemed to have merit but were considered too complex for
the initial Ops Program and not in line with the initial design principles summarized
above. After the Ops Program has been in place for at least one season, the PO may
review these future design elements, using historical data from the Ops Program to
determine their benefit and work with Participants to make enhancements to the Ops
Program where applicable. Design principles that would be applicable to this next phase
or phases of design effort are listed below. This is not a complete list and is meant as a
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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starting point for future discussion. These concepts are covered in more detail in
Sections 3.15 and 3.16 .
Design Principals to be considered later:
• Optimizing Holdback Requirements across RA Participants.
o Minimize transactions.
o Minimize transmission costs and losses.
o Minimize risk of curtailments.
o Maintain balanced benefits for all RA Participants.
• Assess and improve, if applicable, on the design principle of equity to all RA
Participants regardless of the fuel mix of the RA Participant.
• Assess and improve, if applicable, on the design principle of being fair to all RA
Participants regardless of the geographic location of the RA Participant within the
RA footprint.
• Perform a look ahead assessment beyond the 7-day horizon to forecast the
Holdback Requirements and allow RA Participants to use the results to schedule
maintenance outages.
• Minimize the Sharing Events assuring settlement and compensation levels are set
correctly to incentivize RA Participants to solve capacity deficits before holdbacks
or energy deployments are issued.
• Minimize the Sharing Events by implementing incentives for RA Participants to
use their available capacity before leaning on RA Program even if they are
eligible.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 147 of 254
OPS PROGRAM DESIGN FOR GO LIVE
Ops Program Timeline
The Ops Program is implemented over a timeline beginning with a forecast up to a
week prior, revised daily through the preschedule day, and revised hourly into the OD.
Figure 3-1, below demonstrates a high-level summary of the Ops Program timeline for
any given event forecast (all times are shown in Pacific Prevailing Time). Participants
submit hourly forecasts and operating information to the PO. The PO performs Sharing
Calculations and provides a Multi-Day Ahead Assessment for up to the next 7 days in
the forecast window. On the preschedule day the PO will provide Sharing Calculations
and Holdback Requirement for the forecasted ODs. The Sharing Calculations are
performed hourly on the OD to determine the Energy Deployment up to the Holdback
Requirement for each Sharing Event. Any capacity not identified in the Energy
Deployment to be released back to Participants. These steps are described in more
detail in sections below.

Figure 3-1. Overall Ops Program Timeline.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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The steps the PO takes for the preschedule and ODs are shown below in more detail in
Figure 3-2. This timeline covers the actions taken by the PO from the identification of an
event in the preschedule day, through the actual event in the OD.

Figure 3-2. Preschedule & OD Timeline.

Sharing Requirement Calculation
The Sharing Calculation determines if Participants are either needing to access the Ops
Program for capacity shortfall or are positioned to contribute capacity to the Ops
Program. This Sharing Calculation drives the determination of when Sharing Events are
triggered by the PO. Any Participant positioned to contribute to the Ops Program will be
calculated as having a net positive Sharing Requirement, whereas any Participant
needing to access the Ops Program will be calculated as having a net negative Sharing
Requirement.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Sharing Calculation
The Sharing Requirement is described in the Sharing Calculation presented in Table 3-2.
Table 3-2. Sharing Calculation and components.
Definition: Sharing Requirement
𝑺𝒉𝒂𝒓𝒊𝒏𝒈 𝑹𝒆𝒒𝒖𝒊𝒓𝒆𝒎𝒆𝒏𝒕
=[𝑷𝟓𝟎 + 𝑷𝑹𝑴 − 𝜟 𝑭𝒐𝒓𝒄𝒆𝒅 𝑶𝒖𝒕𝒂𝒈𝒆𝒔
+ 𝜟𝑹𝒐𝑹 𝑷𝒆𝒓𝒇𝒐𝒓𝒎𝒂𝒏𝒄𝒆
+ 𝜟𝑽𝑬𝑹 𝑷𝒆𝒓𝒇𝒐𝒓𝒎𝒂𝒏𝒄𝒆] – [𝑳𝒐𝒂𝒅 𝑭𝒐𝒓𝒆𝒄𝒂𝒔𝒕 + 𝜟𝑪𝑹
+ 𝑼𝒏𝒄𝒆𝒓𝒕𝒂𝒊𝒏𝒕𝒚]
P50 The 1-in-2 peak load seasonal values as submitted in the FS
Program for the forecasted upcoming two years.
PRM
Percentage of dependable capacity needed above the 1-in-2 peak
Load Forecast to meet unforeseen increases in demand and other
unexpected conditions. See the FS Design document for more
details.
Δ Forced Outages
Includes any outages or de-rates associated with thermal
generation units, storage hydro units and transmission outages
impacting firm capacity import. Does not include generation on
outage for scheduled maintenance.
Δ VER Performance
Comparison of forecasted VER production vs. qualified capacity
contribution (QCC) of VER. Includes both over and under
performance of wind and solar plants.
Δ Run-of-river
Performance
Comparison of forecasted run-of-river production vs. QCC of run-
of-river hydro. Includes both over and under performance.
Load Forecast: Forecasted load for the OD considering the forecasted weather
conditions of OD.
Uncertainty: Forecast of potential error of the Load Forecast, VER forecast, and
run-of-river forecast.
Δ CR:
Comparison of contingency reserves (CRs) that were included in
the FS Program and CR requirement in Ops Program. Contingency
reserves will be carried into the operating hour as required by the
NWPP CR Sharing Program.

The Sharing Calculation as described above will be utilized to identify any potential
Sharing Events. A Sharing Event is defined as any hour in which the Sharing Calculation
identifies any given Participant as a net negative (i.e., needing to access Ops Program
capacity). Due to the difficulty in forecasting precisely when an event will occur over the
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 150 of 254
horizon of the OD, the PO, at its discretion, may add an hour before and after each
identified event. This Sharing Event Window will ensure that the total possible duration
of the Sharing Event is covered by the Ops Program. For example, if on the preschedule
day the PO forecasts a Sharing Event at hour beginning 04:00 PM PPT of the OD the PO
may extend the Sharing Event to cover hour beginning 03:00 PM – 05:00 PM. Figure 3-3
provides a representation of the Sharing Calculation for a period of ten hours.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 151 of 254

The Ops Program Sharing Calculation will be run for each hour of each Operating Day starting 7-days in advance. The graph to the left is a representation of
the calculation for 10 sample hours.
The yellow and black lines represent the Participant s P50+PRM and Portfolio QCC from Forward Showing. The green, blue, and red bars represent the
forecasted over/under performance and excessive forced outages. The grey bars represent the Participant s P50+PRM adjusted for forecasted performance
and outages. The orange line represents the Participant s Forecasted Load + CR + Uncertainty.
The blue line represents the Participant s Sharing Calculation results. A Sharing Event would be identified when the Sharing Calculation is negative (line
below x-axis, e.g., hours 6, 7, and 8).
-300
-200
-100
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
-300
-200
-100
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1 2 3 4 5 6 7 8 9 10
MW

V
a
l
u
e
Operating Hour
Ops Program Sharing Calculation P50+PRM Adjusted for
Performance
Delta VER
Delta ROR
Excessive Forced Outages
Portfolio QCC
P50+PRM
Forecasted Load + CR +
Uncertainty
Sharing Calculation Result
Figure 3-3. Ops Program Sharing Calculation.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 152 of 254
Forward Showing Capacity Requirement
(P50+PRM)
The starting point for the Sharing Calculation is the FS Capacity Requirement (defined as
P50 + PRM). As previously discussed, this data will be determined in the FS Program and
remain set in the Ops Program. Each Participant will have a P50 representing the
predicted peak forecasted load of any given season, plus the associated PRM for that
same season. As stated, this is the starting point for the calculation and represents what
a Participant “should have” during any given calculated horizon in the Ops Program.
Components that impact the sharing calculation, as identified in Table 3-2, are explained
further in sections below. It is important to note that each Participant will have a unique
FS Capacity Requirement determined by its configuration of load and resource portfolio.
Additionally, there will be a unique FS Capacity Requirement per season of the Ops
Program (i.e., Winter and Summer).
Forced Outages
The forced outages term in the Sharing Calculation covers several items. This term is
utilized by the Program to capture the performance impact of thermal and storage
hydro generation, as well as impacts from transmission outages that impact firm
capacity import. This term will capture both over and under performance on thermal
generation, but only capture under performance on storage hydro generation. This is
due to the fact that storage hydro, for the purpose of this program, is capped at QCC
from the FS in relation to over performance but may be lowered for reliability impacts.
Specifically, this term will cover:
Thermal generating units (coal, gas, biofuel, nuclear, etc.):
• Over and under performance as related to the forced outage rate utilized in the FS to
define the QCC.
• This will include the impact of both forced outages as well as reliability de-rates for
the associated generation plants.
• It will not include forced outages or de-rates related to fuel or economic decisions.
• QCCs will be modified upward for over performance and downward for under
performance. This can impact the availability of a generating plant from a value over
the QCC, up to the maximum capability of the plant, down to zero.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Storage Hydro generating units:
• Under performance only as related to operational reliability impacts and compared
to QCC from FS.
• Performance will be capped at QCC from the FS for over performance.
• Will not include fuel related forced outages or de-rates or economic decisions.
• Forced outages and derates will only be reported if the Participant also had the fuel
available such that they could have otherwise provided the QCC of the Storage
Hydro unit but for the outage/derate condition.
• QCCs will be modified downward only for under performance. This can impact the
availability of a generating plant from a max of the QCC of the plant, down to zero.
Unplanned transmission outages:
• Participant (and/or their supplier) has acquired North America Electric Reliability
Corporation (NERC) priority 6 or 7 service and service contract is de-rated.
• Participant will notify the PO of any de-rate impacts when they are identified so that
impacts will be seen in Sharing Calculations.
• Will be reported in relation to impact on total QCC availability of the import contract
(outage = (service contract de-rate/total service contract)*RA resource)
• QCCs will only be modified downward for contract imports, as related to the
transmission derate impact, otherwise QCC will be defined according to the
principles established above.
• Participants should be able demonstrate good faith effort to secure NERC priority 6
or 7 and unforeseen circumstances (e.g., de-rate before procurement, preempted
without ability to match), as applicable considering the timeline on which these
changes occurred.
• The PO may determine that a forced outage was inappropriately claimed. If this was
the fault of a Participant’s supplier, it is anticipated that the Participant would be able
to pass this penalty on to the supplier through their commercial agreement if they
choose to do so. The PO will track this behavior to identify ‘bad actors. ’
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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• Inability to secure transmission (e.g., remaining 25% not previously demonstrated at
FS deadline) on NERC priority 6 or 7 is not a valid reason on its own to claim a forced
outage in the Ops Program; doing so may result in penalty.
• If a Participant claims a transmission-related forced outage, the PO may request
documentation (including, but not limited to, contracts, transmission contracts,
etags, etc.) to support the Participant’s forced outage report after the fact.
Each Participant will submit reliability-driven outages and derates to the PO to be
utilized in the Sharing Calculation on a generating plant granularity. The PO will utilize
the principles outlined above in order to calculate the actual unit availability of each
generating plant participating in the Program, in respect to the QCC as defined in the
FS. These values will be aggregated from a plant level granularity to a Participant level
and are utilized in the Sharing Calculation, as defined in previous sections.
Note: Generation maintenance outages will not be added to forced outage submissions.
Note: VER and run-of-river forced outages will be reported in VER and run-of-river
under and over performance reporting, respectively, and not be reported under this
metric.
Note: Outages or de-rates associated with economic decisions are not allowed to be
submitted to the PO.
Maintenance Outages
Maintenance outages are necessary and expected during the course of the Ops
Program. However, Participants should minimize the amount of maintenance outages
that are taken over periods of the season in which capacity shortfall has an increased
likelihood of occurring. As such, maintenance outages are taken at the risk of each
Participant. The Ops Program binding season covers the Winter and Summer peaks of
all Participants. As such, it is expected that each Participant will make the generation
available to the Ops Program as calculated in the FS Program.
Any maintenance outages occurring over the horizon of the Ops Program calculations
will not be included in determination of Sharing Requirement, as these plants should be
available in the same manner as determined in the FS Program. It is expected that
Participants will limit planned maintenance over forecasted Sharing Events to ensure
they can fully support the Ops Program. Any capacity accredited from the FS Program
should be available to the Ops Program during these Sharing Events.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Transmission Outages
Transmission system outages that impact path limits and affect the ability of a
Participant to import firm contracted capacity should be reported to the PO. All efforts
should be made by the Participant to resupply the power up until T-105. These outages
will be tracked through the forced outages variable in the Sharing Calculation and will
include the megawatt (MW) amount of the import capability that is reduced for a
Participant.
Participants who are experiencing any impacts from transmission system outages
associated with existing firm import contracts should report these impacts to the PO, as
soon as practical, such that the PO can coordinate across the Ops Program to account
for these system conditions and update the Sharing Calculations to accommodate. For
example, if a Participant is experiencing transmission outages that are impacting its
ability to deliver, the Participant should notify the PO. The PO will make a determination
on these reports on a case-by-case basis to determine how and if they may impact Ops
Program results and any potential delivery failures associated (see sections below for
more details).
Variable Energy Resources Over Performance
and Under Performance
Each VER (typically wind and solar) in a Participant’s generation portfolio will provide
capacity to the Ops Program on a variable basis given forecasted weather and system
conditions. As such, the Ops Program needs to track the performance of these resources
on an hourly basis. The FS Program will determine a QCC for each resource, respectively.
Each Participant should submit resource-specific forecasts to the PO such that these
variations can be considered in the Sharing Calculation.
Run-of-River Hydro Over Performance and
Under Performance
Similar to VER unit performance, run-of-river hydro plants also experience an expected
performance that may vary from what was reported in the FS Program. Each Participant
should submit resource-specific forecasts to the PO such that these variations can be
considered in the Sharing Calculation.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Load Forecast
The Sharing Calculation will need to consider the Load Forecast for the period in which
the calculation is being performed. This calculation is conducted on an hourly basis for
all forecast windows, as described in Section 3.12, below, using the data submitted by
each Participant. This Load Forecast should consider the expected weather forecast and
expected system conditions. Each Participant will submit forecasts to the PO such that
these variations can be considered in the Sharing Calculation. This Load Forecast is a
metric to determine what a Participant should need on any given day and will be
modified by load uncertainty and CR, as described in section 2.3. The Sharing
Calculation will demonstrate the projections for each Participant relative to their
expected peak to forecast the availability of capacity or need for Ops Program support.
This value will be reported as MW on an hourly basis. The granularity of this data
submission is given in more detail in Section 3.12.
Uncertainty
System conditions are often difficult to predict. As such, the PO will include a level of
uncertainty in the Sharing Calculation to account for potential variance. Uncertainty is
the relationship of the accuracy of the performance of historical forecasts, by Participant,
in comparison to historical actuals. This uncertainty will be Participant specific and
include adjustments for possible variations in load, solar/wind, and run-of-river
forecasts. The purpose of this offset is to ensure that, should system conditions change,
the Ops Program is still able to deliver the necessary support to Participants needing to
access the Ops Program.
The level of uncertainty utilized by the PO will be a variable that will continue to improve
as the PO gets more experience with the performance of load, wind, and solar forecast
of each of the Participants. Uncertainty requirements are expected to be variable and
associated closely with the level of risk of each given operating horizon. It will be under
the discretion and authority of the PO to set uncertainty levels to offset these risks. This
value will be a MW value for each hour represented in the Sharing Calculation.
The specifics of this uncertainty calculation will be determined later in the RA Program
when the PO has access to sufficient amounts and quality of forecast and actual data for
each Participant. After phase 2B of the RA Program (see Figure ES-1), the PO and
Participants should continue to review, evaluate, and improve the uncertainty
calculation. As shown in the initial Proof of Concept work by presented by Southwest
Power Pool (SPP) on April 23rd, 2021, accurate forecasts are critical in the reduction of
Holdback Requirement allocation that does not materialize into actual Sharing Events.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Participants who submit forecasts which are unreliable have been shown to greatly
increase the magnitude of potential Sharing Events in the Program. The PO will work
with Participants to communicate on any discrepancies and issues seen with more
forecast data is available.
Safety Margin
The PO has the discretion to determine the need for a Safety Margin to the Sharing
Calculation at a program-wide level. The Safety Margin is an additional amount of
uncertainty beyond the Participant level Uncertainty calculation described in Section
3.3.9. Specifically, this term can be used for situations such as potential large resource
trips, heavy transmission outage conditions, significant environmental conditions, and
other similar region-wide impacts. The additional uncertainty MWs will be split pro rata
amongst those Participants with a positive Sharing Requirement and result in a larger
Holdback Requirement for impacted Participants. The application of a Safety Margin will
not result in a Holdback Requirement greater than a Participant’s Sharing Requirement
as a Participant’s Holdback Requirement (as defined in Section 3.4) is capped at the
Sharing Requirement (as defined in Section 3.3). To maintain transparency, the PO will
notify all Participants when a Safety Margin has been applied including the timeframe,
MW amount, and reasoning. The PO shall develop and maintain a list of criteria for
when to consider implementing a Safety Margin. The criteria will be refined over time as
the PO gains experience.
Contingency Reserves
NOTE: This item is still under discussion and pending a decision prior to determination.
Contingency reserves are the provision of capacity that are set aside and may be
deployed to respond to a contingency event or other contingency requirement. For
each Participant, the expected CR necessary in each timeframe is equal to 3% of total
generation plus 3% of total load. This program is not intended to modify or change the
way in which the NWPP CRs Sharing Program operates. This program will continue to
operate under the current prescribed rules, terms and conditions set forth. The Ops
Program does not replace or duplicate the NWPP CR Sharing Program.
The Ops Program will account for any variations in CRs between the Sharing Calculation
and FS Program inclusions. For example, if the FS Program decides to forego adding CR
to its determination, then the Ops Program would include all CR. If the FS Program
decides to include CR in its determination, then the Ops Program would forego the
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 158 of 254
addition of this level of CR and only be adjusted to account for any variations in what
was assumed in the FS Program. In that case, this term would change to ΔCR.
Holdback Requirement Calculation
Prescheduling Practices
The Ops Program will respect the Western Electricity Coordinating Council (WECC)
Prescheduling Calendar. The default prescheduling days are:
Scheduling on: Monday Tuesday Wednesday Thursday Friday
Scheduling for: Tuesday Wednesday Thursday Friday &
Saturday
Sunday &
Monday

For a given OD, the PO will conduct the Sharing Calculation assessment on the WECC
prescheduling day at 04:45 AM. Participants of the Ops Program must have all
requested forecast data for the given OD submitted to the PO by 04:30 AM on the
prescheduling day. Exceptions to the default prescheduling practice will be
accommodated for holidays and new months as specified by WECC. When the
prescheduling day is not the day prior to the OD, the PO will rerun the Sharing
Calculation each interim day (see Section 3.5.1).
The Sharing Calculation assessment that is performed on the prescheduling day sets the
Holdback Requirement, and comparable forecast calculations are performed multiple
days ahead as described in Section 3.2. While no action is required by the Participants
ahead of the preschedule day, the forecast calculations will give Participants a good
indication of the state of the footprint, and the ability to estimate what their final
Holdback Requirements or assistance amounts will be on and after the preschedule day.
Sharing Event
The PO performs the Sharing Calculation on the preschedule day and any other interim
days between the preschedule day and the OD. A Sharing Event may be identified by
the PO when a Participant was calculated for one or more consecutive hours as having a
net negative Sharing Requirement. Due to the difficulty in forecasting precisely when an
event will occur over the horizon of the OD, at the discretion of the PO, a Sharing Event
Window may begin an hour prior to the Sharing Event and conclude an hour following
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 159 of 254
the Sharing Event. For example, if the PO forecasts a Sharing Event at hour ending 17,
the PO may identify a Sharing Event Window from hour ending 16 –18. When the
Sharing Event Window is expanded, the appended hours will reflect the risk that the
hour of deficit MW may extend beyond the window identified in the Sharing Calculation.
This Sharing Event Window will ensure that the total possible duration of the Sharing
Event is covered by the Ops Program.
The Sharing Event calculation is performed during the Multi-Day Ahead Assessment,
though the results are not binding. This information will be provided to Participants for
situational awareness (see Section 3.5.2).
Holdback Requirement
For a given hour during a Sharing Event, on preschedule day, the PO will calculate the
Holdback Requirement. Participants with a positive Sharing Requirement will be
assigned an hourly Holdback Requirement in MW. This Holdback Requirement amount
will be the pro rata share among Participants with a positive Sharing Requirement equal
to the total of net negative Sharing Requirements. For hours with no Sharing Event,
Participants will not have a Holdback Requirement. Pro rata sharing is defined with the
formula in Table 3-3.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 160 of 254
Table 3-3. Participant Holdback and pro-rata sharing calculations.
Definition: Participant Holdback Requirement
𝐏𝐚𝐫𝐭𝐢𝐜𝐢𝐩𝐚𝐧𝐭 𝐇𝐨𝐥𝐝𝐛𝐚𝐜𝐤 𝐑𝐞𝐪𝐮𝐢𝐫𝐞𝐦𝐞𝐧𝐭
=𝐏𝐚𝐫𝐭𝐢𝐜𝐢𝐩𝐚𝐧𝐭 𝐒𝐡𝐚𝐫𝐢𝐧𝐠 𝐑𝐚𝐭𝐢𝐨
∗𝐓𝐨𝐭𝐚𝐥 𝐏𝐫𝐨𝐠𝐫𝐚𝐦 𝐒𝐡𝐚𝐫𝐢𝐧𝐠 𝐑𝐞𝐪𝐮𝐢𝐫𝐦𝐞𝐧𝐭
Where:
𝐏𝐚𝐫𝐭𝐢𝐜𝐢𝐩𝐚𝐧𝐭 𝐒𝐡𝐚𝐫𝐢𝐧𝐠 𝐑𝐚𝐭𝐢𝐨
=𝐩𝐨𝐬𝐢𝐭𝐢𝐯𝐞 𝐒𝐡𝐚𝐫𝐢𝐧𝐠 𝐑𝐞𝐪𝐮𝐢𝐫𝐞𝐦𝐞𝐧𝐭𝑷𝒂𝒓𝒕𝒊𝒄𝒊𝒑𝒂𝒏𝒕
∑𝐧𝐞𝐭 𝐩𝐨𝐬𝐢𝐭𝐢𝐯𝐞 𝐒𝐡𝐚𝐫𝐢𝐧𝐠 𝐑𝐞𝐪𝐮𝐢𝐫𝐞𝐦𝐞𝐧𝐭𝑷𝒂𝒓𝒕𝒊𝒄𝒊𝒑𝒂𝒏𝒕

𝐓𝐨𝐭𝐚𝐥 𝐏𝐫𝐨𝐠𝐫𝐚𝐦 𝐒𝐡𝐚𝐫𝐢𝐧𝐠 𝐑𝐞𝐪𝐮𝐢𝐫𝐦𝐞𝐧𝐭
=∑𝐧𝐞𝐠𝐚𝐭𝐢𝐯𝐞 𝐒𝐡𝐚𝐫𝐢𝐧𝐠 𝐑𝐞𝐪𝐮𝐢𝐫𝐞𝐦𝐞𝐧𝐭𝑷𝒂𝒓𝒕𝒊𝒄𝒊𝒑𝒂𝒏𝒕

During the performance of the Sharing Requirement and Holdback Requirement
calculations, when any Participant is found to be deficient, the PO will notify each
Participant with a negative Sharing Requirement to verify. Participants who are assigned
a Holdback Requirement are also notified and asked to confirm the obligation. The
calculated Holdback Requirement will be posted by 05:00 AM. The deficient Participant
may waive all or a portion of their negative Sharing Requirement by 05:30 AM and the
PO will adjust the Holdback Requirement calculation accordingly; whether the deficient
Participant would need to affirmatively request the holdback is pending decision. In the
event that a Participant submits a waiver of Sharing Requirement, the calculated
Holdback Requirement will be re-posted by the PO by 05:45 AM. Figure 3-4 provides an
example of the Holdback Requirement for three Participants.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 161 of 254

Figure 3-4. Holdback Requirement example showing three Participants.

RA Transfers
Participants may elect to transfer capacity between one another to meet their FS
capacity requirement out of the FS Program. Settlement of this capacity transfer is
between Participants with no interaction from the PO. Adequate transmission service
should be available as described in section 3.7. This is to ensure that the Ops Program is
not exposed to any potential deliverability issues and to ensure that capacity transfers
cannot be used as a mechanism to get around transmission showing requirements. A
Participant may be involved in multiple RA transfers, but must be purely a purchaser of
capacity, or a seller of capacity. In other words, a single Participant may not purchase
capacity from one Participant while also selling capacity to another Participant for a
single Sharing Event.
In the case where a Participant who had purchased a transfer was calculated as having a
negative Sharing Requirement, that transfer will first be utilized to serve the deficiency.
In the case where a Participant who had purchased a transfer was calculated as having a
positive Sharing Requirement, that transfer contract will be fully utilized before the
purchasing Participant is required to use their own resources to meet their Holdback
Requirement. This approach ensures that capacity transfers between Participants does
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 162 of 254
not inadvertently affect the Holdback Requirement Calculation for the remaining
Participants. In the case of multiple contracts, the contracts will serve the Holdback
Requirement, either positive or negative, on a pro-rata basis up to 100%.
The PO will calculate the Sharing Requirement with (first pass) and without (second
pass) consideration of the transfer in order to determine if the transfer should be
provided to the purchasing entity in the case that they have a negative Sharing
Requirement or provided to another Participant in the case that the purchasing entity
has a positive Sharing Requirement. Table 3-4 provides examples of several scenarios
for Sharing Requirement Calculations.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 163 of 254
Table 3-4. Examples of Sharing Requirement Calculations.

Example: Participant A contracts with Participant B to assume 100MW of Participant
A’s RA Obligation.
Participant A Participant B
FS Obligation Prior to
Transfer:
FS Capacity Requirement = 3450
MW
FS Capacity Requirement = 4600
MW
FS Obligation After Transfer 3450 MW – 100 MW = 3350 MW 4600 MW + 100 MW = 4700 MW
Note: If Participant A is calculated as having a negative Sharing Requirement, Participant B would
serve the first 100 MWs to Participant A. If Participant A is calculated as having a positive Sharing
Calculation, Participant B would serve the first 100 MWs of Participant A’s Sharing Requirement.
Example 1
In the first pass of the Sharing Requirement Calculation, Participant A is calculated 125 MWs
deficient when considering the 100 MW transfer to Participant B. In this case Participant B serves
the first 100 MWs. The second pass of the Sharing Requirement Calculation results in a deficit of the
remaining 25 MWs that would be served pro-rata by the Participants with positive Sharing
Calculations, including Participant B.
Example 2
In the first pass of the Sharing Requirement Calculation, Participant A is calculated 25MWs deficient
when considering the 100 MW transfer to Participant B. In this case Participant B serves the entire
25 MW deficit. In the second pass, the remaining 75 MWs of transfer is shown as a positive Sharing
Requirement for Participant A, with Participant B being responsible to serve any Holdback
Requirement assigned to Participant A, up to 75 MWs.
Example 3
In the first pass of the Sharing Requirement Calculation, Participant A is calculated as having a
positive 200 MW Sharing Requirement when considering the 100 MW transfer to Participant B.
Since Participant A is not deficit there is no need to call on Participant B and the transfer. In the
second pass of the Sharing Requirement Calculation, Participant A is calculated as having a
positive 300 MW Sharing Requirement when not considering the 100 MW transfer to
Participant B. In this case Participant B would be responsible to serve any Holdback
Requirement assigned to Participant A, up to 100 MWs, with Participant A being responsible for
any Holdback Requirement in excess of the 100 MW transfer.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 164 of 254
Bilateral Exchange of Holdback Requirement
The Ops Program will support the bilateral exchange of Holdback Requirement capacity
between Participants. Figure 3-5 shows a bilateral exchange of Holdback Requirements
overlaid on a Sharing Calculation timeline. The PO will host a virtual bulletin board
system where Participants can coordinate this exchange. After the preschedule day
calculations have run, and Participants are notified by 05:00 AM of their Holdback
Requirement, and potentially updated at 05:45 AM. Participants may then utilize the
bulletin board to initiate contact with other Participants to exchange part or all of their
Holdback Requirement.
Securing transmission service for a potential energy delivery of the exchanged capacity
is the responsibility of the partnering Participants. Likewise, settlement of any capacity
obligation exchanged between Participants will be the responsibility of the partnering
Participants, with no involvement from the PO (described further in sections below).
Any exchange of Holdback Requirement between Participants should be reported to the
PO no later than two hours (T-120) prior to the operating hour for which the Holdback
Requirement was assigned (T). The PO will use the Holdback Requirement values for
each Participant, accounting for all reported exchange, when performing the pro-rata
Energy Deployment calculation at T-105.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 165 of 254

Figure 3-5. Bilateral Exchange of Holdback Requirement overlaid on Sharing Calculation
timeline.

Release of Capacity
Day-Ahead Release of Capacity
After performing Sharing and Holdback Calculations on the prescheduling day, the PO
will set the hourly Holdback Requirement for each Participant. If no Participant is
calculated to be deficient for the given OD, and the PO has not applied a Safety Margin
to that OD, all capacity will be released. If during the preschedule day calculations, the
PO defines a Sharing Event for the given OD, the hourly Holdback Requirement for each
Participant will be set. With the exception of bilateral exchange of Holdback
Requirement activities, a Participant’s Holdback Requirement is capped at the initial
value calculated on the preschedule day. Subsequently, any additional, unused capacity
is released back to the Participant as illustrated in Figure 3-6, where LPS is the net
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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positive Sharing Requirement and SPS the negative Sharing Requirement. PS refers to
preschedule.
Figure 3-6. Preschedule Release of Excess Holdback Capacity.

In instances where the preschedule day is not the day prior to the OD, the Holdback
Requirement will be recalculated on each incremental day.
When the preschedule day is not the day prior to the OD, the PO will rerun the Sharing
Calculation each interim day. For example, on a typical Friday the PO will perform the
Sharing Calculations for the coming Sunday and Monday ODs and will also rerun the
Sharing Calculation on Saturday for Sunday and Monday ODs and again on Sunday for
Monday OD. Each rerun of the Sharing Calculation may result in a reduction to the
Holdback Requirement values for Participants, but will be capped at, and never higher
than, the prior Holdback Requirement values.
Additional release of excess Holdback Requirement capacity may occur through Energy
Deployment as described in Section 3.6.2.
Multi-Day Ahead Assessment
The Ops Program will include a Multi-Day Ahead Assessment which will provide a look
ahead at the next seven ODs and determine the need for and magnitude of potential
Sharing Events (see Figure 3-7). For example, on a Monday, the Multi-Day Ahead
Assessment would consider Tuesday (OD-6) through the following Monday (OD). Once
daily, Participants will submit hourly load, wind, solar and forced outage forecast data
for the next seven ODs to the PO. The PO will then perform a look ahead calculation
considering historical levels of uncertainty for forced outages and load, wind, and solar
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 167 of 254
forecasts. This assessment will mimic the Sharing Calculation but will not result in
assignment of Holdback Requirement to Participants. This information will be given to
Participants through the Program Interface Tool.

Figure 3-7. Overall Ops Program Timeline.

If the Multi-Day Ahead Assessment indicates a low risk of a potential Sharing Event, the
PO may consider early release of a portion, and up to all, of the capacity held by
Participants. Additionally, if the Multi-Day-Ahead Assessment indicates a potential for a
large Sharing Event, the PO will notify the Participants, providing notice that they might
not be able to fully rely on the Ops Program for a given timeframe, allowing Participants
time to look for alternatives to meet their demand. This is anticipated to be rare event
and the PO will conduct the Ops Program to avoid these situations.
Multi-Day Ahead Release of Capacity
Based on the results of the Multi-Day Ahead Assessment, the PO may consider the
release of capacity back to the Participants. This may range from a collective release of
capacity for all Participants, to an ad-hoc release of capacity at the request of
Participants. Participants may submit a request to the PO for consideration of early
release of a portion, and up to all, of their capacity. The PO will review requests for early
release and assess the associated risks. Once capacity has been released back to a
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 168 of 254
Participant that capacity is no longer available to be called on by the Ops Program. The
PO will make appropriate adjustments to the Sharing Calculation, if necessary.
The PO will create and maintain a list of acceptable reasons for Participants to request
an early release. The list may include but is not limited to urgent outages that do not
qualify as “forced” and long lead resources that cannot be started within the timeframe
needed. The PO will develop a process for assessing a high volume of release requests
where more capacity is being requested for release than what is available for early
release.
NOTE: Pending a future Program Decision. Potential options are: by order of when the
request was made, pro rata of all requests or prioritization by category of request. If PO
determines that a Participant is regularly requesting release and therefore not
contributing to holdback needs, future releases can be denied without reason.
Energy Deployment
Frequency of Data Submission on Operating
Day
On a given OD, Participants will send data (e.g., load, VER performance, run-of-river
performance, and forced outages) hourly to the PO for all remaining hours of the OD,
starting at 12:00 AM on the OD. For example, at 01:00 AM a Participant would send
forecast data to the PO for hour beginning at 02:00 AM through hour beginning at
11:00 PM. At 02:00 AM a Participant would send forecast data to the PO for hour
beginning at 03:00 AM through hour beginning at 11:00 PM. For ease of setting up the
data exchange, Participants may elect to send forecast data to the PO in a rolling 24-
hour window, with the hours beyond the given OD going unused except as a last good
data set due to submission errors. For more details on data submission types see
Section 3.12.
Energy Deployment Calculation
As the Ops Program enters the OD, the Holdback Requirement that is a capacity (MW)
value will be converted to an Energy Deployment which is an hourly energy (MWh)
value. Energy Deployment calculations will be performed by the PO starting at 105
minutes prior to each hour (T-105) identified in a Sharing Event Window using the latest
set of forecast data provided by Participants from T-120. Final Energy Deployment
values (in whole MWh increments) will be communicated back to Participants at T-90.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 169 of 254
All capacity that was not part of final Energy Deployment values is released back to
Participants at this time.
The total Energy Deployment needed will equal the sum of the MWs that short entities
are calculated deficient for a given hour. The Energy Deployment allocated to long
entities will be a pro rata calculation of a Participant’s final Holdback Requirement. Final
Energy Deployment values will be set at T-120, and any exchange of Holdback
Requirement amongst Participants should be reported to the PO by this time. In
summary, forecast values and Holdback Requirement exchange will be provided to the
PO by T-120, the PO will run Energy Deployment calculations at T-105, and final Energy
Deployment values will be communicated to Participants at T-90. Figure 3-8 shows an
example timeline for a Sharing Event Window from hour beginning 01:00 PM through
hour beginning 03:00 PM. Any deficiencies in this calculation are covered in section 3.13.
During the performance of the Energy Deployment calculations, when any Participant is
found to be deficient, the PO will notify each Participant with a negative or positive
Sharing Requirement to verify. The deficient Participant may waive all or a portion of the
energy due to be scheduled to them, and the PO will adjust the Energy Deployment
calculation accordingly.
In the event that a Participant was calculated deficient in the prescheduling day but is
no longer deficient for the hour in question based on forecast values from T-120, that
Participant’s Energy Deployment is set at zero. While the Participant may have excess
capacity available, they did not receive an initial Holdback Requirement, and therefore
will not be made to deploy energy. This is consistent with maintaining a Participant’s
Energy Deployment as no greater than the previously calculated Holdback Requirement.
Any extreme situations for this Energy Deployment are covered in section 3.13.
Tagging Energy Deployment
Tagging of assigned Energy Deployment must be completed by T-60. Participants
providing capacity will be responsible for deploying and tagging energy to a centroid23.
Deficient Participants will be responsible for receiving and tagging energy from the
same centroid. Participants may agree on alternate delivery, when more efficient and/or
economic means of delivery are available and agreed upon between the impacted
23 A central location on the electric grid utilized to transact power to and from in order to provide
for a known location to enact RA Program deliveries.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 170 of 254
Participants. The PO will audit actual Energy Deployments for given events, as covered in
Section 3.11.
The default use of a centroid will require a hosting BAA to approve tags and ensure tags
to and from the centroid initiated by the Ops Program net to zero. This will require a
BAA volunteering to take on this responsibility. The volunteering BAA would have the
Point of Receipt/Point of Delivery that represents the centroid within their BAA
boundary. The PO may need to develop additional functionality to assist the hosting
BAA in balancing the tags to and from the centroid. If the PO cannot reach an
agreement with a BAA to host a centroid, tagging will be done directly between
Participants.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 171 of 254

Figure 3-8. Energy Deployment Timeline Example.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 172 of 254
Centroid Options
Note: Pending a Program Decision prior to determination. There is debate between the
Program starting with a single centroid or up to two centroids. This section would be updated
to reflect that decision once it is made.
Using centroids simplifies delivery and receipt of energy, without requiring direct Participant
to Participant scheduling. This is especially helpful in instances where there are multiple
deficient Participants, as a Participant may only need to deliver to a single centroid with a
single tag instead of being required to tag energy to multiple Participants. Use of a centroid
may also simplify allocation by the PO and exchange by Participants of Holdback
Requirement and Energy Deployment. There are multiple approaches for implementing the
centroid design which are discussed in the following subsections. Note that with all of these
options, Participant to Participant exchange of Holdback Requirement and Energy
Deployment is allowed. Bypassing a centroid to tag energy directly between Participants is
also acceptable.
3.6.4.1. Single Centroid
The single centroid approach is the most simplistic option and would most likely make use of
the existing Mid-C Trading Hub. By default, all energy delivered through the Ops Program
would source to and from the one centroid. A single centroid would allow for an aggregation
of schedules in the case that multiple Participants are delivering energy to the same deficient
Participant. The approach also simplifies exchange of Holdback Requirement and Energy
Deployment between Participants and simplifies settlements. The major drawback to using a
single centroid is that there is not a single delivery point in the footprint that is equally
accessible by all Participants and use of the Mid-C Hub would require potentially expensive
legs of additional transmission by a subset of Participants.
3.6.4.2. Two Centroids without Shared Transmission between Centroids
The two centroid approach would likely use the Mid-C Trading Hub as one of the centroids,
and then identify a second centroid that is more easily accessible by Participants not located
close to Mid-C. There are a few ways in which the two centroid approach may be
implemented. Specifically, an option without exchange between the centroids, covered here,
and an option without exchange between the centroids, covered in the following section.
In the method without exchange between the centroids, each Participant chooses which
centroid they want to interact with, and all assigned delivery to or receipt of energy takes
place at that centroid. This essentially splits the Program into two, with Participants only
sharing diversity benefit with other Participants that are associated with the same centroid.
A possible variation of the approach without exchange is for Participants to continue to
deliver energy to their preferred centroid, but deficient Participants take receipt of energy
from both centroids, as available. In this variation, the burden is placed on the deficit
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 173 of 254
Participant to receive energy as provided by the delivering Participants to their chosen
centroids. If multiple Participants are deficient, the PO may optimize delivery of energy
between the two centroids.
The two centroid approach increases accessibility to the Ops Program for those Participants
that are not located near Mid-C and may facilitate Ops Program expansion due to that
accessibility. Depending on how the second centroid is implemented, diversity benefit may be
impacted. This option also complicates the PO’s role of allocating Holdback Requirement and
Energy Deployment, while also complicating settlements. Ideally, the two centroid approach
will maximize value with these centroids having ample delivery between each other, as
covered below in section 3.6.4.3.
3.6.4.3. Two Centroids with Shared Transmission between Centroids
This two-centroid approach is similar to the option described in the section above, with the
addition of transmission between the centroids being reserved on behalf of the Ops Program
with associated costs being shared by all Participants. Each Participant would choose their
preferred centroid and would deliver and receive all energy from that centroid. The PO would
calculate the net of energy to be delivered from one centroid to the other.
Like the previous two centroid option, this approach increases accessibility to the Ops
Program for those Participants that are not located near Mid-C and may facilitate Ops
Program expansion due to that accessibility. This approach also allows for access to the entire
footprint’s diversity without complicating the PO’s role of allocating Holdback Requirement
and Energy Deployment.
There are several challenges with this approach. It is unclear who would be responsible for
reserving centroid-to-centroid transmission, and it potentially complicates settlement of
Energy Deployment. This approach also complicates the exchange of Holdback Requirement
and Energy Deployment between Participants. It would most likely be acceptable for
Participants with the same assigned centroid to exchange these products. However, exchange
of Holdback Requirement between Participants with different assigned centroids might not
be allowed if the result was an increase of the potential centroid to centroid transfer. Also,
exchange of Energy Deployment between Participants with different assigned centroids
would not be allowed as it would change the amount of energy to be tagged between
centroids, and the PO would need that value to be static once Energy Deployment values
were assigned 90 minutes prior to a given hour on the OD. Lastly, how transmission service
will be allocated between centroids, across the RA Program footprint.
Scheduling Deadline
The Ops Program will use T-60 as the scheduling deadline for tagging Energy Deployment.
Participants will receive their final Energy Deployment value for a given operating hour at T-
90 and have until T-60 to tag that energy. The T-60 timeframe allows for the tagged energy
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 174 of 254
to be included in the Western Energy Imbalance Market (EIM) energy sufficiency tests and
other data inputs to the EIM. The PO will not verify tags during OD. This check will be done
after the fact as defined in Section 3.12.4 below.
Bilateral Exchange of Energy Deployment
Participants will be allowed to exchange Energy Deployment. Participants will receive their
final Energy Deployment value for a given operating hour at T-90. Participants then have up
until T-60 to exchange their Energy Deployment with other Participants as long as all final
Energy Deployments are tagged prior to T-60. The PO will host a virtual bulletin board to help
match Participants wanting to lower their assigned Energy Deployment with Participants
requesting to take on additional Energy Deployment. Participants will utilize the bulletin
board to initiate and coordinate the exchange of their Energy Deployment with other
Participants. Participants will notify the PO of any changes made to their assigned Energy
Deployment after the fact.
Transmission Service
Transmission service will be required to support the delivery of energy in the Ops Program.
This section of the report covers the requirements of transmission service in the Ops Program.
Securing Transmission for Delivery to Load
On PS-1, if at least one entity is forecasted by the PO to have a negative sharing calculation
for at least one hour, all entities will be responsible for demonstrating additional NERC
priority 6/7 transmission for that hour(s). FS Program requirements for procuring transmission
from generating resource to load and transmission firmness apply (see Section2.8).
The additional procurement obligation will be the difference between a Participant’s
transmission demonstrated at FS and
what is forecasted necessary for their
load [Hourly PS Tx obligation = hourly
load forecast – (0.75*FS Requirement) +
forecasted hourly holdback]. As in the FS
portfolio, this requirement can be met
with transmission rights or contracts with
appropriate transmission provisions.
Transmission must be acquired by the
end of the PS day.
Example
Participant A’s P50+PRM is 1000 MW, has
demonstrated >750 MW. PS-1 forecasts a
Participant (different Participant) with a negative
sharing calculation. Participant A’s forecasted load
is 800 MW, and they are forecasted for a 30 MW
holdback. They will be responsible for
demonstrating NERC priority 6/7 transmission for
an additional 80 MW from an RA resource or an
alternative reliable source of supply.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 175 of 254
Firmness of Transmission Service Requirements
Unless coordinated otherwise between Participants, transmission service will be scheduled for
Energy Deployment to a centroid for delivery in the Ops Program. (See Section 3.6.3). In this
arrangement, Ops Program Participants who are scheduled long will be designated to deliver
energy to a centroid. Ops Program Participants who are scheduled short will be designated to
take delivery from this same centroid. This will result in a set of delivering Participants and
one or more receiving Participants.
It will be the obligations of the delivering Participant that the service available is dependable
and reliable in delivery. The delivering Participant will enact delivery either to the centroid or
in a direct-delivery arrangement (as described in Section 3.6.4). As such, the delivering
Participant is strongly encouraged to secure firm transmission service for the Ops Program. If
the delivering Participant secures firm transmission service and is still unable to deliver the
energy due to transmission complications, such as curtailment, then the delivering Participant
will be exempt from Delivery Failure Penalties. If the delivering Participant utilizes non-firm
transmission service for delivery, and the delivery results in failure, then that Participant will
be exposed to Delivery Failure Penalties (see Section 3.11).
The receiving Participant is responsible for securing transmission service for receipt of energy
from the centroid or in a direct-delivery arrangement (as described in Section 3.6.4). It is
strongly encouraged that the receiving Participant secure firm transmission service for the
delivery. However, the receiving Participant will secure the available transmission service at its
own risk and at the level, which is reasonably reliable. Failure of the receiving Participant to
secure transmission does not relieve the receiving Participant of requirements to pay
settlement for requested Energy Deployment.
Participants should be aware of and follow current Open Access Transmission Tariff (OATT)
practices when securing transmission service. Each Participant, when redirecting long-term
firm service, needs to be aware of how these redirects will change the prioritization of that
service (e.g., long-term firm being redirected as short-term non-firm).
Securing Transmission Service
Each Participant shall assess the need for securing transmission service for the Ops Program
months ahead, day-ahead, or hour-ahead. This assessment should be based on the likelihood
of the need to deliver energy in these periods, the risk associated with the securement of
service, and the cost associated with carrying the service. For example, for paths that have a
known risk for the award rate of service, Participants should work to anticipate this risk and
potentially secure transmission. Conversely, for paths that are low risk for being denied
transmission service, it may be more prudent for a Participant to secure service on a day-
ahead or hour-ahead basis.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 176 of 254
Additionally, while the transmission service associated with the FS Program typically is
configured for delivery to each Participant’s respective load, the Ops Program is configured
for delivery to a centroid or receipt from a centroid. While it may be possible to redirect long-
term transmission service, as needed, Participants need to be aware of what is available and
the impact on prioritization of service.
Role of PO with Respect to Transmission Service
The PO may review Participant’s transmission obligations as outlined above, and the PO will
always review delivery failures of RA resource when there is a sharing or reliability event.
Participants that request a sharing holdback or delivery, fail to provide a holdback or energy
deployment when requested, or experience a reliability event are subject to such review. The
PO may request information from Participants pursuant to such review activities.
Consequences and penalties for issues identified in these reviews will be considered further in
Phase 3A and will be viewed in light of whether: 1) another entity is harmed, or 2) no harm is
experienced. There may be exceptional regional events where penalties would be waived.
Further considerations related to potential repercussions could relate to delivery of specific
resources (e.g., increasing the transmission demonstration quantity at showing deadline for
the following year by failure quantity).
Ultimately, it is the responsibility of each Participant to secure transmission service such that it
has a reasonable likelihood of being awarded in times of shortfall. The Participant should
work with the PO on known issues with the procurement of transmission service. The PO will
maintain a list of paths which are known to have risk to the award rate and provide notice of
when these paths are to be needed in the determination of delivering and receiving parties.
Deliverability Assessment & Path De-
Rates
The PO will not make engineering calculations as to the availability of the transmission
service. This responsibility will remain the role of the Transmission Service Provider (TSP)
facilitating the acquisition of service. The PO will not be responsible for monitoring
transmission system outages that affect deliverability. The role of the PO is in the reporting
and facilitation of information in situations where a transmission path may pose risk to the
reliability of energy delivery. In these situations, the PO will post information on at-risk
transmission paths to the notice of all Participants. Additionally, if Participants become aware
that a path may be at-risk, it is obligated to report this information to the PO for
consideration. The PO will post this information on a bulletin board system such that all
affected Participants are aware of the situation.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 177 of 254
If the path de-rate happens prior to the preschedule day, the PO will recalculate the Holdback
Requirements on an as needed basis. This will result in a total Holdback Requirement that
takes into consideration the inability to secure delivery across the affected transmission paths
due to known path de-rates. For path de-rates that occur any time after the preschedule day,
the Holdback Requirements will not be recalculated and will remain as posted. The existing
Holdback Requirements include both uncertainty, as well as a safety margin, that is meant to
account for variance between the preschedule and OD. These additional buffers should be
sufficient to account for the majority of these occurrences. In instances where the margins are
not adequate, and there is still a shortfall for Participants, emergency procedures will be
enacted (see Section 3.14).
Settlements
Energy Deployment and Holdback Settlement
3.9.1.1. Pricing and Settlement Principles
To ensure a well-functioning RA Program, it is critical that the settlement pricing be calculated
appropriately. Pricing should encourage entities with a negative Sharing Requirement to
address capacity shortfalls using other means before accessing the program’s pooled
capacity. When those entities with a positive Sharing Requirement holdback and/or deliver
energy, the pricing should adequately compensate their contribution to the program without
being punitive to entities truly in need.
The calculation of settlement price should conform to the following principles:
» Utilize existing systems/processes (bilateral transactions)
» The Program Operator or Administrator may calculate the settlement amount but has no role
in the transaction
» Requests for holdback capacity and requests for energy delivery should each be priced to
incent Participants to utilize pooled capacity as the resource of last resort
» Energy delivery prices should not be punitive to buyers. Though, an entity truly in need of help
should pay a fair price.
» Sellers should be fairly compensated for requested holdback capacity and/or delivered energy.
Prices should include opportunity costs.
3.9.1.2. Settlement Price Calculation
The proposed settlement price is based on the California Independent System Operator
(CAISO) methodology for implementing Federal Energy Regulatory Commission (FERC) Order
831. This methodology has the benefit of having been developed with significant stakeholder
input, was presented to, and accepted by FERC, is shaped using a shaping factor that reflects
changes in energy/capacity value from hour to hour and can be based on locational indices
(Mid C, Palo Verde (PV) as examples.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 178 of 254
The settlement price is based on a regional index price, shaped hourly, plus a 10% adder.
Definition: Total Settlement Price
𝐓𝐨𝐭𝐚𝐥 𝐒𝐞𝐭𝐭𝐥𝐞𝐦𝐞𝐧𝐭 𝐏𝐫𝐢𝐜𝐞
=𝐇𝐨𝐮𝐫𝐥𝐲 𝐒𝐡𝐚𝐩𝐢𝐧𝐠 𝐅𝐚𝐜𝐭𝐨𝐫
× 𝐀𝐩𝐩𝐥𝐢𝐜𝐚𝐛𝐥𝐞 𝐈𝐧𝐝𝐞𝐱 𝐏𝐫𝐢𝐜𝐞× 𝟏𝟏𝟎%
Where:
− The 𝐇𝐨𝐮𝐫𝐥𝐲 𝐒𝐡𝐚𝐩𝐢𝐧𝐠 𝐅𝐚𝐜𝐭𝐨𝐫 is selected based on the most recent High-Priced Day. A
High-Priced Day is a when at least a single hour in the day has a system marginal energy
cost (SMEC) greater than $200. If no High-Priced Day exists in the current season, it will
look to the most recent High-Priced Day of the same season in previous years.
=𝟏+[𝑪𝑨𝑰𝑺𝑶 𝑯𝒓𝒍𝒚 𝑫𝑨 𝑺𝑴𝑬𝑪−𝑪𝑨𝑰𝑺𝑶 𝑨𝒗𝒈 𝑫𝑨 𝑺𝑴𝑬𝑪(𝒐𝒏 𝒐𝒓 𝒐𝒇𝒇𝒑𝒆𝒂𝒌 𝒉𝒐𝒖𝒓𝒔)
𝑪𝑨𝑰𝑺𝑶 𝑨𝒗𝒈 𝑫𝑨 𝑺𝑴𝑬𝑪(𝒐𝒏 𝒐𝒓 𝒐𝒇𝒇𝒑𝒆𝒂𝒌 𝒉𝒐𝒖𝒓𝒔)]

− The 𝐀𝐩𝐩𝐥𝐢𝐜𝐚𝐛𝐥𝐞 𝐈𝐧𝐝𝐞𝐱 𝐏𝐫𝐢𝐜𝐞 is the day ahead heavy load/light load (HL/LL) ICE Index
price based on the location of the delivering entity. For example, this may be the Mid-
C or PV price published for the day and hour when the holdback and/or energy is
requested.

3.9.1.3. Application of the Settlement Price
The Settlement Price is split into two components, 1) a capacity price for confirming the need
for a holdback in preschedule, referred to as the Holdback Settlement Price, and 2) an
energy price charged for any energy dispatched in the operational program after a holdback
has been confirmed, referred to as the Energy Settlement Price.
The Total Settlement Price is then split into its two underlying components: the Energy
Declined Settlement and the Holdback Settlement Price.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 179 of 254

Definition: Energy Declined Settlement Price
𝐄𝐧𝐞𝐫𝐠𝐲 𝐃𝐞𝐜𝐥𝐢𝐧𝐞𝐝 𝐒𝐞𝐭𝐭𝐥𝐞𝐦𝐞𝐧𝐭 𝐏𝐫𝐢𝐜𝐞
=𝐥𝐞𝐬𝐬𝐞𝐫 𝐨𝐟{𝑨𝒑𝒑𝒍𝒊𝒄𝒂𝒃𝒍𝒆 𝑯𝒐𝒖𝒓𝒍𝒚 𝑰𝒏𝒅𝒆𝒙 (𝑻𝑩𝑫)
𝑺𝒆𝒕𝒕𝒍𝒆𝒎𝒆𝒏𝒕 𝑷𝒓𝒊𝒄𝒆 × 𝟖𝟎%
80% factor ensures that sellers will receive at least 20% for
carrying holdback regardless of energy deployment. Factor can
be discussed and adjusted.
Definition: Holdback Settlement Price
𝐇𝐨𝐥𝐝𝐛𝐚𝐜𝐤 𝐒𝐞𝐭𝐭𝐥𝐞𝐦𝐞𝐧𝐭 𝐏𝐫𝐢𝐜𝐞
=𝐓𝐨𝐭𝐚𝐥 𝐒𝐞𝐭𝐭𝐥𝐞𝐦𝐞𝐧𝐭 𝐏𝐫𝐢𝐜𝐞
−𝐄𝐧𝐞𝐫𝐠𝐲 𝐃𝐞𝐜𝐥𝐢𝐧𝐞𝐝 𝐒𝐞𝐭𝐭𝐥𝐞𝐦𝐞𝐧𝐭 𝐏𝐫𝐢𝐜𝐞
+𝐌𝐚𝐤𝐞 𝐖𝐡𝐨𝐥𝐞 𝐀𝐝𝐣𝐮𝐬𝐭𝐦𝐞𝐧𝐭

Final Settlement For Any Applicable Hour
𝐅𝐢𝐧𝐚𝐥 𝐒𝐞𝐭𝐭𝐥𝐞𝐦𝐞𝐧𝐭 (𝐟𝐨𝐫 𝐚𝐧𝐲 𝐚𝐩𝐩𝐥𝐢𝐜𝐚𝐛𝐥𝐞 𝐡𝐨𝐮𝐫)
=(𝐇𝐨𝐥𝐝𝐛𝐚𝐜𝐤 𝐒𝐞𝐭𝐭𝐥𝐞𝐦𝐞𝐧𝐭 𝐏𝐫𝐢𝐜𝐞
× 𝐇𝐨𝐥𝐝𝐛𝐚𝐜𝐤 𝐌𝐖 𝐑𝐞𝐪𝐮𝐞𝐬𝐭𝐞𝐝)
+(𝐄𝐧𝐞𝐫𝐠𝐲 𝐒𝐞𝐭𝐭𝐥𝐞𝐦𝐞𝐧𝐭 𝐏𝐫𝐢𝐜𝐞
× 𝐎𝐩𝐞𝐫𝐚𝐭𝐢𝐨𝐧𝐚𝐥 𝐄𝐧𝐞𝐫𝐠𝐲 𝐌𝐖𝐡 𝐃𝐢𝐬𝐩𝐚𝐭𝐜𝐡𝐞𝐝)

3.9.1.4. Other Considerations
It is assumed that the holdback and delivery will primarily occur on Heavy Load hours. The
shaping factor is calculated for all hours of the day, so it is possible to calculate a Light Load
holdback and delivery settlement price using the corresponding Light Load index. For
example, the PO may add additional hours to the start or end of a forecasted sharing event
that might include Light Load hours.
As well, in order to ensure that participants asked to provide holdback are kept whole
(compared to making a daily market sale), and in keeping with the “last resort” principle
above, a Make-Whole Adjustment will also be calculated. The Make-Whole Adjustment will be
calculated in such a way as to attempt to ensure that any participant that is required to
provide holdback to others will be no worse off than if they were able to sell the maximum
hourly amount of the holdback obligation into the daily market, within reason.
This proposal does not address issues such as settlement mechanics, credit/collateral
considerations, invoicing etc. It is presumed that these details are of less importance than
price formulation and will be addressed in a later phase of the project.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 180 of 254
It should be noted that the final details of the deployment and holdback settlements are still
being discussed by the participants and will be finalized in coming phases.
Transmission Service
Transmission service charges will follow existing OATT practices for the respective TSP. The
delivering Participant is responsible for transmission service charges of delivery. The receiving
Participant is responsible for transmission service charges of the receipt.
Interaction of Ops Program and EIM /
EDAM
There will be minimal coordination required between the Ops Program and the EIM and
Extended Day-Ahead Market (EDAM).
Note: EDAM is still pending, and these details are highly subject to change. Currently, there
are no expected adverse impacts of the EIM or EDAM and the NWPP RA Program.
The Sharing Calculation for Holdback Requirement is done on the preschedule day and any
interim ODs at 05:00 AM, prior to the EDAM Sufficiency Evaluation performed between 09:00-
10:00 AM. Participants with an assigned Holdback Requirement will not bid that capacity in
the EDAM. If a Participant has exchanged their assigned Holdback Requirement to another
Participant prior to the EDAM Sufficiency Evaluation, that Participant may then bid that
capacity in the EDAM. Participants that are deficient and are expecting support from the Ops
Program based on the results of the Sharing Calculation may count the expected support as
capacity in the EIM/EDAM sufficiency evaluation.
Tagging of assigned Energy Deployment from the Ops Program is to be done no later than
60 minutes prior to the operating hour (T-60). This timing requirement ensures that Energy
Deployment tags are considered as inputs for the EIM calculations.
Failure to Deliver Energy
Deployment
Notification of Failure to Deliver Energy
Deployment
An Ops Program Participant that receives an hourly Holdback Requirement is responsible for
Energy Deployment up to that assigned Holdback Requirement value as identified by the PO
during the preschedule day. If a Participant with a Holdback Requirement anticipates that
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 181 of 254
they will not be able to cover an Energy Deployment that Participant should notify the PO as
soon as possible and at least 120 minutes prior to a given hour (T-120) during the OD. A
Participant has up until T-120 to exchange their Holdback Requirement and may pursue this
exchange to avoid a potential delivery failure. The PO will then adjust the pro rata Energy
Deployment calculation for the anticipated shortfall, resulting in a higher Energy Deployment
for the remaining Participants that have a Holdback Requirement. In the case where there is
not enough Holdback Requirement to cover the deficiency after accounting for any
anticipated delivery failure, Energy Deployment will be capped at the Holdback Requirement
values and the PO will implement emergency procedures (Section 3.14). A Participant who
notifies the PO prior to T-120 of a potential failure to deliver Energy Deployment is seen as
having a delivery failure, regardless of whether remaining Participants are able to cover the
shortfall.
If the PO is notified by a Participant after T-120 of a potential delivery failure, the PO will not
make adjustments to Energy Deployment for that potential delivery failure. In this instance of
late notification of delivery failure, the PO will implement emergency procedures where
applicable.
Assessing & Waiving Penalties for Delivery Failure
A Participant that notifies the PO of a potential failure to deliver Energy Deployment, and/or
fails to deliver their assigned Energy Deployment, may be subject to penalty. The PO will
develop and maintain a process for the evaluation of delivery failures as agreed upon by the
Participants. The PO will utilize this process to assess and grant waivers to Participants for
failing to deliver Energy Deployment.
If the PO determines that the Participant’s reason for delivery failure is valid, penalties may be
waived. All cases of delivery failure will be reviewed by a Committee of Participants, described
in the section below. The Review Committee will look for persistent delivery failures, as well as
review special case circumstances.
Delivery Failure Review Committee
The RA Program will create a committee to review waiver disputes from Participants and
excessive delivery failures by individual Participants for a given season. The RA Program will
be responsible for developing and maintaining a process for selecting committee members,
and that committee will agree on the details of the review process.
The committee will convene, first reviewing any waiver disputes submitted by Participants for
delivery failures during that season, and then assessing if any Participants had an excessive
number of delivery failures during that same season. Any Participant that has three or more
non-waived instances of delivery failure in a single season will be subject to review by the
committee. The Participant will be given the opportunity to explain the circumstances that led
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 182 of 254
to their failure to deliver, and the committee will then make an assessment. Possible
consequences of excessive delivery failure range from increasing the FS Capacity Requirement
by the average capacity that the Participant failed to deliver, to expulsion from the RA
Program. Expulsion may be permanent or for a defined number of seasons.
The RA Program and a review committee will allow for flexibility in the first binding season of
the Ops Program and refine the details of the review process as experience is gained. The
review process will be aligned with criteria for entering and leaving the RA Program.
Load Shedding Responsibility
In the event that Holdback Requirement totals are less than the need from deficient
Participants and load shed is imminent, the deficient Participant(s) will bear the burden of
shedding load via existing procedures and programs by the associated BAA. Deficient
Participants will be eligible to receive up to the full amount of capacity available as defined by
the prescheduling day calculations. When the capacity available to the Ops Program is not
sufficient to cover deficient Participants, the PO will implement emergency procedures to call
on all Participants to provide support beyond their calculated Holdback Requirement. If the
additional support gained from implementing emergency procedures still leaves a Participant
with a deficit that Participant would then be responsible to work with their BAA to issue
Energy Emergency Alerts (EEA) and implement load shedding as necessary. Participants may
have other means outside of the Ops Program to avoid shedding load (NERC Alert, Merchant
Alert, EEA, Extended CR Support, Interruptible Load, etc.).
In the event that a Participant fails to deliver their Energy Deployment, and that failure results
in load shed by a deficient Participant, the deficient Participant will bear the burden of
shedding load. The Participant that failed to deliver will not be requested to shed load but
would instead be subject to the penalty process.
Penalty for Delivery Failure
Participants who fail to deliver their assigned Energy Deployment and do not secure a waiver
for that failure will be subject to penalty (see Table 3-5 for examples of penalty calculation).
Collected penalties for failure to deliver Energy Deployment will be used to offset the
administrative cost of the RA Program. The penalty for not delivering the assigned Energy
Deployment depends on the impact of the failure on the deficient Participant(s).

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 183 of 254
Table 3-5. Penalty calculation examples.
Definition: Penalty for delivery failures
If a Participant fails to provide energy and that deficit is entirely covered by other
Participants of the Program, the proposed penalties are as follows:
First non-waived
delivery failure
5 times the index price of the default centroid for the undelivered
megawatt hours (MWhs)
Second non-waived
delivery failure
10 times the index price of the default centroid for the undelivered
MWhs
Third or more non-
waived delivery failure
20 times the index price of the default centroid for the undelivered
MWhs and be cause for review for expulsion by the committee as
defined in Section 3.11.3
If a Participant fails to provide energy and that deficit is not entirely covered by other
Participants of the Program, the penalties are as follows:
First non-waived
delivery failure
25 times the index price of the default centroid for the undelivered
MWhs
Second or more non-
waived delivery failure
50 times the index price of the default centroid for the undelivered
MWhs and be cause for review for expulsion by the committee as
defined in Section 3.11.3

The above penalty schedules are meant to be used as applicable and are not separate tracks.
For example, if a Participant’s first non-waived delivery failure is covered by other Participants,
the penalty would be set at 5 times the index price. If the Participant then had a second non-
waived delivery failure and that failure was not covered by other Participants, the penalty
would be set at 50 times the index price.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 184 of 254
Data Submission Requirements for
Ops Program
Participants are required to submit the data in
Table 3-6 to the PO. For each data type, the
Participant should submit data for the start of each
hour (i.e., hour beginning). Figure 3-9 presents a
high-level data submission timeline. The data
submission guidelines will be further described in
more detail during system design in a later stage
of the Program design (See SPP presentation on
Program Interface Tool). For example, OD 0900 will
cover 09:00 AM – 10:00 AM. The data will cover all
hours in each operating window, as described in
subsequent sections. The generation data will be
submitted on a resource level (e.g., wind forecast,
solar forecast, forced outages, etc.). The remainder
are on a Participant level.

Figure 3-9. Timeline for data submission.

Multi-Day Ahead Data Submission
Each day, at 04:30 AM, Participant will submit data for each OD in the given horizon. This
horizon will include OD-1 through OD-7. For each day in the forecast, Participants will submit
Table 3-6. Data to be submitted by
Participants to PO.
Hourly forecast data to be submitted
to PO:
Load Forecast data for all hours
Wind forecast data for all hours
Solar forecast data for all hours
Run-of-river forecast data for all hours
Contingency Reserve forecast data for all
hours
Megawatts forced out and de-rated
generation by plant
Reliability generation unit de-rates for all
hours
Transmission path de-rates impacting firm
contracts from the FS Program
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 185 of 254
hourly data listed in Table 3-6. This data submission will include 24 hourly periods for each of
the submission days listed.
Operating Day Data Submission
On the OD, starting at 12:00 AM, each Participant shall send the data as listed in Table 3-6 for
each remaining hour of the OD. This data will continue on each subsequent hour and include
each hour remaining for that OD. For example, on OD at 02:00 AM, data will be submitted for
hour beginning 03:00 AM through hour beginning 11:00 PM.
Data Submission Errors and Validation
Data submitted to the PO will be checked for errors, including incorrect or missing
submissions, stale data, or any other causes for data errors. If data errors are detected, the PO
will contact the Participant in order to get the errors rectified. If this is not possible, the PO
will use the last good data set in order to increase the accuracy of the Ops Program
calculations.
After Fact Data Submission
Each Participant will submit to the PO actual data for the data sets listed in Table 3-6. This
data will be used by the PO to perform statistical analysis for increased forecasting accuracy.
Additionally, the data will be assessed to verify that Ops Program deliveries and holdback
were accomplished according to the instruction of the PO. Data will not be shared with any
external parties, with the exception of special requests such as from regulatory agencies. The
timelines for submission of this data will be developed by the PO at a later date.
Notification Process
The PO will facilitate a program interface tool that will be used as the primary means of
communication between the PO and Participants. The PO will use this tool to notify
Participants of: Multi-Day Ahead Assessment results, known WECC path de-rates, Sharing
Events, assigned Holdback Requirement and Energy Deployment. Participants will use this
tool to acknowledge receipt of Holdback Requirement and Energy Deployment. Participants
may also use this tool to inform the PO of any exchanged Holdback Requirement or Energy
Deployment. If the PO does not receive acknowledgement of receipt of Holdback
Requirement or Energy Deployment in a timely manner, the PO will follow up with verbal
communication to the Participant. Participants should communicate all delivery failure
notifications to the PO verbally and in writing.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 186 of 254
Emergency Procedure
In times when the Ops Program is unable to support a deficient Participant through typical
procedures, the PO may use the Emergency Procedure to call for additional help from the
Participants at large. The Emergency Procedure may be used to call for additional capacity or
energy as applicable. Emergency Procedure calls are purely voluntary for Participants and will
not increase the Holdback Requirement or Energy Deployment values for any Participant who
does not volunteer to participate.
If Sharing Requirement Calculations reveal that the sum of the negative Sharing Requirement
is greater than the sum of the positive Sharing Requirement, this indicates that the RA
footprint as a whole is insufficient. In this instance, all Participants with a positive Sharing
Requirement would have 100% of their Sharing Requirement assigned as Holdback
Requirement. The PO would then issue an insufficiency notification to all Participants, and
request for Participants to provide additional capacity to the RA footprint. The PO would then
work with any willing Participants that volunteered additional capacity to the pool and adjust
Holdback Requirements as applicable.
If the Energy Deployment calculations reveal that the sum of the Holdback Requirement is
insufficient to cover the energy needs of deficient Participants, Holdback Requirement will be
converted to Energy Deployment at 100%. The PO will then issue an insufficiency notification
to all Participants, and request for Participants to provide additional energy to other
Participants. The PO would then work with any willing Participants that volunteered additional
energy to the other Participants and adjust Energy Deployment as applicable. Consistent with
Section 3.11.4, following exhaustion of the Emergency Procedures, load shedding
responsibility or other mitigation of the remaining deficiency rests as the responsibility of the
deficient Participant(s).

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 187 of 254
REVIEW OF DESIGN ELEMENTS
Review of Design Elements After
First Season
The following sections of the Operational Design document cover topics for future
consideration. These are areas that SPP feels the PO should evaluate and monitor to improve
the Program. The PO should monitor the health and performance of the RA Program and
continually endeavor to make it better. This section provides some key areas in which this
work could focus.
After the Ops Program has run for at least one season, the Participants and the PO will have
gained experience and may decide to analyze and adjust design elements of the Ops
Program. The Ops Program and processes as initially designed are based on assumptions that
are believed to provide the best possible results for all Participants. This is done by balancing
the following objectives: maintain reliability, operate under an acceptable risk threshold,
provide equitable benefits and costs across all Participants, fair treatment of all Participants
and a low operating cost. As the PO and Participants gain experience with the Ops Program,
adjustments will continue to keep the Ops Program in line with these objectives.
Potential areas to analyze and fine-tune include:
• Number of Sharing Events determined by Sharing Calculation
• Magnitude and use of uncertainty
• Magnitude and frequency of use of safety margin
• Location of centroid(s)
• When to add a buffer hour to the beginning and end of each Sharing Event
• Variance of Participant’s load and wind forecast accuracy and whether to incorporate
into the Sharing Calculation
• Whether the penalty structure for delivery failures correctly incentivizes Participants to
minimize delivery failures
• The impact the Ops Program has on Participants depending on the makeup of their
capacity portfolio
• Use of Multi-Day Ahead release of capacity, weighing operational risk against
economic benefit
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 188 of 254
• Compensation/Settlement are correct incentives for Participants to use the program as
a Resource of Last Resort, and not the first option
Review of Design Elements for
Future Consideration
While designing the Ops Program, the development of several design elements was put on
hold. These design elements were deemed to have merit but were considered overly complex
for the initial Ops Program. After the Ops Program has been finalized and in place for at least
one season, the PO may review these future design elements, using historical data from the
Ops Program to determine their benefit and work with Participants to make enhancements to
the Ops Program where applicable.
Multi-Stage Sharing Calculation
Participants that have a generation mix that is heavy in renewables may have a different
experience in the participation of their resource fleet compared to more traditional type of
generation fleets. This is due to the over performance of wind, solar and un-of-river
generation being included in the Sharing Calculation, and those resource types being
accredited at a lower percentage than thermal resources in the FS Program. As such, the
expected availability of these types of resources can be highly volatile and is reliant on given
system conditions.
To account for the impact, the Ops Program could implement a multi-stage Sharing
Calculation (see Table 3-7). The first stage would consider only the load diversity benefit of
the Ops Program, and not account for over performance of wind, solar and run-of-river
generation. If stage one did not provide enough diversity benefit to cover all deficient
Participants, stage two would then consider the resource diversity benefit, and include the
over performance of wind, solar and run of river in the Sharing Calculation.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 189 of 254
Table 3-7. Multi-stage Sharing Calculation.
Definition: Multi-stage Sharing Calculation
Sharing Calculation A:

[FS Capacity Requirement – ΔForced outages – VER under performance + VER over
performance – Run-of-river under performance + Run-of-river over performance]

– [Load Forecast + Uncertainty + CR]
Sharing Calculation B:

[FS Capacity Requirement – ΔForced outages – VER under performance – Run-of-
river under performance]

– [Load Forecast + Uncertainty + CR]

The PO would first perform Sharing Calculation A to determine if any Participants are
deficient. This ensures that a Participants over performance of VERs and run-of-river
resources are considered. If a Sharing Event is identified, the PO would use Sharing
Calculation B to calculate the Holdback Requirement for all long Participants. Then, if Sharing
Calculation B does not result in enough capacity to cover the deficient Participant, then
Sharing Calculation A would be used to supplement the remaining Holdback Requirement.
Note that it may be desirable to set the Holdback Requirement from Sharing Calculation B as
a minimum value before rerunning Sharing Calculation A. Otherwise, depending on the
makeup of a Participants fleet, their Sharing Requirement may be lowered.
Seasonal Look Ahead Assessment of Sharing
Events
The Ops Program will be binding for a total of eight months (a four- and one-half month
Winter season and a three- and one-half month Summer season) in a twelve-month cycle. For
the given binding season, a Participant is required at any time to be able to meet their FS
Capacity Requirement as calculated in the FS Program. This obligation may not leave
adequate time for Participants to perform planned maintenance outages on their fleet of
resources. Though the RA Program is binding throughout the seasons as defined (see Table
3-1), there are times at the beginning and end of a given season when Sharing Events would
be unlikely. While a Participant may not have the necessary data to analyze and determine the
risk of performing planned maintenance on these seasonal shoulders, the PO does have high-
level awareness of the RA footprint and is in a position to help Participants determine the
likelihood of a Sharing Event for a specific timeframe.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 190 of 254
The PO could perform a look ahead Sharing Requirement Calculation for each upcoming
season and share the results with all Participants. The calculation would use historically
conservative values instead of forecasted values (high load, low wind, low solar, high forced
outage rate) and provide results with weekly granularity. This would approximate a worst-case
estimation, calculating the odds of having a Sharing Event for a given week within the season,
and provide a potential Holdback Requirement for each Participant. Participants could then
use the results of this calculation to schedule maintenance outages while lowering the risk to
the RA Program as a whole. One point for further discussion would be what risks Participants
are allowed to take in regard to scheduling maintenance outages during a binding season,
and if the preschedule day Sharing Calculation will take into account results of the look ahead
assessment. Currently, maintenance outages are “at the risk of the Participant”. This step
would be purely informational to each Participant to use as they see appropriate.
Monitoring the Health of the RA Program
The PO may desire to monitor the health of the RA Program throughout the season. This
would require additional data from Participants in order for the PO to calculate the RA of the
footprint for each OD.
Potential inputs to the calculation:
• Total usage of capacity of conventional resources
• Scheduled and forced resource outages
• De-rates of conventional generation
• De-rates of hydro considering available water in river and reservoirs
• Load, wind, and solar forecasts based on most accurate available weather forecast
• Known import and export commitments of each Participant
• Offline, longer lead time capacity not available within time frame of the assessment
• Operating reserves
Given the amount of data needed, the PO would need to work with Participants after
operating the Ops Program for several seasons to determine the added benefit.
Considerations for discussion include: if the Participants can make the required data available
to the PO, whether data would be submitted for individual resources or aggregated by
resource type, the accuracy of forecast data, how often the health check would be initiated
and what actions the PO may take based on results.
Optimizing Holdback Requirement
The PO could do optimization of Holdback Requirement utilizing manual adjustments for
efficiency. Prior to the start of a season the Participants would agree on guidelines for
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 191 of 254
optimization. The optimization should result in changes to Holdback Requirement
assignments that are more efficient and cost effective.
Some possible guidelines for consideration:
• When several Participants are calculated short, use a zonal approach to match those
Participants who are deficient with long Participants that are closest in proximity.
• A minimum threshold for Holdback Requirement such as 5 MW. If a Participant is
calculated to have a Holdback Requirement under the defined threshold that
Participant’s Holdback Requirement would be set to zero, and the corresponding
amount would be allocated to the remaining long Participants.
This sort of manual approach would not require sophisticated software and automation but
would require more staff time and human intervention which could introduce risk of mistakes
or inefficiencies. After implementing a manual optimization process for several seasons, there
could then be a decision made of whether to implement more sophisticated optimization
software.
Optimization should only be done on the day prior to the OD, and not on the preschedule
day when the preschedule day is more than one day prior to the OD. Participants may still
utilize Holdback Requirement exchange but should wait until after the optimization by the PO
is conducted.
Settlement of Optimized Holdback Requirement
The optimization of Holdback Requirement would necessitate the development of a
settlement process for the optimization. The PO could track the unused portion of the
Holdback Requirement optimization exchange for each Participant over a season. The balance
could be MW based or potentially dollar based if Participants agreed on a pricing mechanism
for the exchanged capacity. Participants may settle their balance after each season, or it could
be decided to roll balances forward to the next season. The PO would be able to calculate the
amount owed from and to each Participant and issue bilateral schedules between Participants
to settle all balances.
Capacity Ratio
Note: On 4/09/2021 the Operations Design Team voted on support for Capacity Ratio. The
majority of Participants did not feel it was the preferred solution. As such, it has been
removed from the base design and deferred for future consideration.
The RA Program may later decide to include a Capacity Ratio, exclude a Capacity Ratio or
have it as an option for each Participant to select for their participation in the Program.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 192 of 254
To accommodate the reporting of outages across the percentage of capacity in the Ops
Program versus surplus capacity beyond the Ops Program, one possible recommendation put
forth has been the addition of a Capacity Ratio to the Sharing Calculation, as shown in Table
3-8.
Table 3-8. Capacity Ratio.
Definition: Capacity Ratio
Sharing Requirement = [FS Capacity Requirement + Capacity Ratio * (-ΔForced
outages + Δ Run-of-river performance + ΔVER performance)] – [Load Forecast + CR +
Uncertainty]
Capacity Ratio = (FS Capacity Requirement ) / Total Portfolio QCC

This additional multiplier would adjust the Sharing Requirement for each Participant and
allocate variances in the ΔForced outages, Δ Run-of-river performance, ΔVER performance
terms across the portfolio of each Participant. The impact of this addition would decrease the
Sharing Requirement for both over and under performance of these terms. This option
assumes that during capacity-limited periods, Participants will utilize their surplus in order to
help make themselves whole. Additionally, the calculations will increase the surplus of
Participants during times of over performance.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 193 of 254
SECTION 3: APPENDIX A – PROCESSES &
PROCEDURES
A.1. Summary of Processes and
Procedures the PO Will Develop &
Maintain
Program Administrator processes and procedure framework:
• PO: Perform Sharing Calculations – Procedure that the PO will follow for performing
the Sharing Calculation in determining Holdback Requirements, Sharing Event
Windows, and Sharing Requirements. This includes steps for setting the variable inputs
to the Sharing Calculation and provisions for re-running the Sharing Calculation. The
procedure also specifies steps for evaluating results and communicating to
Participants.
• PO: Sharing Event Analysis – Procedure that defines how to perform post Sharing
Event analysis, when to initiate the penalty process, and provisions for evaluating
penalty waiver requests.
• PO: Address Participant Notifications – Procedure guide that outlines the expected
PO actions in response to various Participant notifications. This includes, but is not
limited to, transmission limitations, replacement capacity concerns, inability to meet
Energy Deployments, bilateral exchanges, and early release requests.
• PO: Emergency Procedure – Procedure that includes steps for identifying when the
Ops Program is unable to support a deficient Participant and how to implement the
Emergency Procedure for volunteer assistance.

A.2. Summary of Requirements for RA
Participants
Requirements of Participants may be captured in the following manner:
• NWPP Operational RA Participant Guidelines – Outlines the requirements and
expectations of Participants as they engage in the Program and includes the following
topics:
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 194 of 254
o Data Submission – Descriptive requirements for forecast/actual data
submissions, including data formats, periodicity, and communication protocols.
o Notifications – Outline expectations for how and when Participants will notify
the PO regarding transmission limitations, at-risk paths and path de-rates,
replacement capacity concerns, inability to meet Energy Deployments, bilateral
exchanges, early release requests, and others as needed.
o Transmission Service – Captures the guidelines related to securing transmission
service, applicable scheduling deadlines, and bilateral exchange.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 195 of 254

NWPP Resource Adequacy
Program Detailed Design

Appendix - 2B Stakeholder Advisory
Committee Engagement and
Feedback

JUNE 2021

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 196 of 254
The Northwest Power Pool’s (NWPP) Stakeholder Advisory Committee (SAC) was formed in late
2019 as the RA Program Development Project began Phase 2A. The stated intent in creating
such a committee was to seek broad representation from across the region, with each member
acting as the liaison for their sector. The sectors were defined as: state representatives
(commissions, state energy offices), public power stakeholder groups, environmental
community stakeholders, independent power producers, large consumers, ratepayer advocacy
groups, and natural gas utilities. The committee was set up to be advisory to the Steering
Committee as they considered program design concepts.
Throughout Phase 2A (October 2019 – June 2020) the SAC met at least quarterly for updates
on program design. When the Phase 2A Conceptual Design document was released in August
2020, the SAC asked to provide written comments on the document. This matrix was also
provided to Southwest Power Pool (SPP) as the Program Developer and referenced regularly
during design meetings to inform Steering Committee discussion on design elements. These
comments were included in the Steering Committee’s internal 2B design progress matrix, and
used to track the evolution of program design details through Phase 2B; as such, these
comments were reviewed weekly with the Steering Committee as each design element was
considered. The full list of SAC comments of the 2B Conceptual Design and the written
responses from the Steering Committee can be found at the end of this appendix.
In Phase 2B, the Steering Committee held quarterly half-day SAC meetings as well as additional
technical workshops (2-3 hours) as requested by SAC feedback. Below is a summary of the
meetings held and topics covered:
• August 21, 2020 – Quarterly SAC meeting: 2A conceptual design and SAC process
improvements
• October 28, 2020 – Technical workshop: Program framework and benefits (by the
Program Developer) and interplay with State Integrated Resource Plans (IRPs) [with
Maury Galbraith, Western Interstate Energy Board (WIEB)]
• January 14, 2021 – Combined quarterly SAC meeting and technical workshop: Design
updates, Energy Imbalance Market (EIM)/ Extended Day-Ahead Market (EDAM)
interplay, contracting paradigms, and Q&A of conceptual design questions
• March 12, 2021 – Technical workshop: Comparison with the California Independent
System Operator (CAISO) – planning reserve margin (PRM) and unforced capacity
(UCAP) methodologies and low water years
• April 28, 2021 – Quarterly SAC meeting: Design updates and governance
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 197 of 254
• June 9, 2021 – Technical workshop: qualified capacity contributions (QCCs) – hybrid and
customer resources, variable energy resource (VER) zones, transmission zones, and
grandfathered contracts
• June 30, 2021 – Quarterly SAC meeting: Governance updates, transmission, interchange
analysis, contingency reserve in PRM, and proof-of-concept analysis
Within 30 days of each SAC meeting, the Steering Committee hosted a public webinar. These
webinars were scheduled for 90 minutes and covered a slightly abridged version of the SAC
materials. These were free, open to the public, and advertised on the NWPP webpage; an email
was sent to the NWPP mailing list with registration information.
While the SAC is primarily an advisory committee, the Steering Committee took suggestions
and comments into consideration and acted on them where possible (acknowledging that
comments and requests from different members were at times contradictory). Table 4-1.
demonstrates a non-exhaustive list of examples where the Steering Committee was able to be
responsive to the SAC and/or the Steering Committee and SAC’s comments were aligned.
Table 4-1. Examples of Steering Committee responses to SAC Feedback
Date
Received Comment Response/Action
8/21/2020 Request for more technical
meetings/discussions
Scheduled technical workshops on: Program
Benefit, State/IRP Interplay, Demand
Response, EIM/EDAM Interplay, Contracting
Paradigms, PRM, Low water years.
8/21/2020 Request for technical experts
from outside the region
Southwest Power Pool hired as the Program
Developer to help with design, bringing
extensive experience in RA (both their own
program and requested additional research
on best practices) - Program Developer spoke
at next SAC meeting. Throughout the
detailed design process, Steering Committee
worked with SPP to consider all available
options for design elements (e.g., from other
RA Programs across the US and occasionally
abroad).
8/21/2020 More consideration for low
water years
Presented additional detail for discussion at
the March 12, 2021, SAC meeting.
Committed to a detailed stress test analysis
of hydro QCC methodology – See Section
D.2.3. Stress Case Analysis.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 198 of 254
Date
Received Comment Response/Action
8/21/2020 Request for a breakout
session on EIM/EDAM
linkage
Jan. 14, 2021, SAC meeting focused on this
topic.
8/21/2020 Request for technical
workshop on contracting
Jan. 14, 2021, SAC meeting focused on this
topic.
4/28/2020 Request to fully consider
resources from third party
providers
Design is technology neutral and will fully
accept resources from 3rd party providers.
Request that owners register their resources
with future PO to determine appropriate QCC
value of resources.
4/28/2020 The RA Program should
comply with Federal Energy
Regulatory Commission
(FERC) principles for
independence in board
composition and program
administration, especially
when binding
That is the expectation as presented at SAC
Apr. 28, 2021.
4/28/2020 Would existing long-term
contracts to buy electricity
from outside entities
(independent power plant
operators, power brokers)
factor into a utility’s RA
evaluation? How would the
capacity contribution be
evaluated and how would
the rules include such
transactions?
Working on “Grandfathering” methodology.
See Section: Grandfathered Agreements
(page 69).
4/28/2020 Robust inclusion and fair
pricing of DR resources
Included in Section 2.5.6 Customer Resources
and presented at technical workshop on Jan
14, 2021.
The RA Program will not determine prices for
any RA resource contracts – contracts will be
negotiated bilaterally.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 199 of 254
Date
Received Comment Response/Action
2/7/2020 Participation of
nontraditional elements in a
Resource Adequacy Program
(customer-owned resources
or direct access providers
that are not IPPs)
Point of compliance will be the Load
Responsible Entities (see Section 1.3 Resource
Adequacy Program Participants).
SAC
Comments
on 2A
Suggest an annual update of
seasonal PRM based on
changes in load and shift in
peak demand hours. This
would be essential for RA
entities to inform short-term
capacity planning as more
renewable and storage
resources come online.
Included in Section 2.10 Modeling Process
Timelines.
SAC
Comments
on 2A
Pumped hydro storage
resources and battery
storage resources are
essential to long-term
reliability, flexibility, and grid
integration of renewables
Both are included with QCC methodology in
Section 2.5.4 Energy Storage.
SAC
Comments
on 2A
5-years of historic data for
thermal resources
Included in Section B.5.1. Thermal Generators
SAC
Comments
on 2A
Longer-term multi-year
contracting for capacity

This aligns with RA Program design as seen in
Section 2.4.2 Sale and Purchase Transactions.
Presented at the January 14, 2021, SAC
meeting.
SAC
Comments
on 2A
Obligations transferred
among participating entities
Included in Section 2.4.2 Sale and Purchase
Transactions.
SAC
Comments
on 2A

Planned outages will not be
included in UCAP
calculations - critically
important that resources
present scheduled outages
in the RA workbook to
adequately represent the full
This is included in Section B.5.1. Thermal
Generators.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 200 of 254
Date
Received Comment Response/Action
availability of the resource
during capacity critical hours
6/8/2020

Request for a preliminary
example FS workbook
Provided example on NWPP website.
4/28/2021 Questions about non-NWPP
participation in Program
Stood up Load Service Information Forum to
address and educate broader group that may
be interested in RA Program.
4/28/2021 Request for consideration of
an Independent Program
Monitor
Included in Section 1.5 Independent
Evaluator.
6/18/2021 Recommend process to
engage state regulators on
RA Program design and
governance.
Stood up series of meetings to engage states
in collaboration with WIEB Western
Interconnection Regional Advisory Body in
late June 2021.
6/18/2021 Request multi-sector
nominating committee with
voting rights.
Included in Section 1.2.1 Makeup of the
Nominating C.
6/24/2021 Recommend that
independent board
members should have term
limits.
Included in Section 1.1 Board of Directors.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 201 of 254
Table 4-2. SAC feedback from 2A Conceptual Design
Stakeholder Comments Steering Committee (SC) Response
Western
Resource
Advocates

Governance and Transparency
− Recommends that the NWPP SC clearly distinguish
the role of the PA versus the role of program
oversight and evaluation. The day-to-day operation
of the program should be separate from the
oversight and evaluation of the program in order to
meet FERC’s independence requirements.
− To be effective, independent program monitoring
and evaluation must be transparent. Every effort
should be made to aggregate data in order to
preserve its confidentiality, while still effectively
communicating program results to stakeholders.
− The Steering Committee (SC) anticipates that the fully operational
program with binding compliance obligations will contain some
functions that are (Federal Energy Regulatory Commission (FERC)
jurisdictional; FERC’s independence criteria and the implications for
oversight (such as a market monitor) versus day-to-day program
operations (by the Program Administrator (PA)) will be more fully
explored in Phase 2B of the program design.
− The SC agrees that transparency is important and expects that the
PA will make aggregate data available, where possible, to
communicate program results to stakeholders once the Resource
Adequacy (RA) program is operational. This level of detail has not
yet been determined but will be considered and determined later in
the process when the PA is hired.
Resource Capacity Contribution and Demand Side
Resources
- An effective and robust regional RA Program should
fundamentally be technology agnostic.
- While demand-side resources will have a role in the
NWPP RA Program, it remains unclear how these
resources will be accounted for (i.e., demand side or
supply side). RA recommends the SC create a
technical workgroup to design an effective
implementation pathway for demand-side
resources.
- The SC agrees that a regional RA Program should be technologically
neutral. This is intended to convey that the qualifying capacity
contribution of resources will be determined based on the resource’s
anticipated contribution to regional reliability in capacity critical
hours, the hours within a day where the delta between forecasted
net load and generation is the smallest. The intent of the program is
not to exclude any resource types that members may choose to
meet their requirements, but rather to appropriately accredit
capacity based on the operating characteristics of the resource.
- The role of demand side resources in the program is being more
fully considered as part of the Phase 2B scope and will be further
discussed with the advisory committee during Phase 2B.
Program Interaction with Current and Planned Regional
Market Initiatives
− WRA believes that the RAPDP, when operational, is
likely to have impacts on transmission deliverability
and the Resource Sufficiency Test for both the EIM
and EDAM. WRA recommends the formation of a
technical work group that can analyze the
− The SC intends to discuss the topic of RA Program interaction with
current and planned regional market programs and initiatives in a
Stakeholder Advisor Committee (SAC) technical workshop.
− Further technical discussions with the SC and the Program
Developer (PD) will determine the day ahead and real-time
requirements and outline the role of the PA in this time horizon. This
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Stakeholder Comments Steering Committee (SC) Response
interaction of relevant RAPDP program design
elements with the EIM and EDAM.
would include how Participants will be assessed as being compliant
during the operational timeframe, which may involve metrics that
take into account actual operational conditions. Within the day
ahead and real-time windows, member entities also participate in
various existing wholesale bilateral and organized markets (e.g.,
Energy Imbalance Market (EIM)). In Phase 2B, the SC and PD will
further consider how the operational program design will integrate
with these markets, including the potential overlay between RA and
RS metrics in the day ahead timeframe.
Northwest
Requirements
Utilities

General Remarks
- Supports exploring an RA Program and believes it
could help capture diversity benefits and ensure
proper compensation for the provision of capacity.
- NRU members as BPA load-following customers, will
not directly participate in the RA Program, but will
be impacted by BPA’s participation. Any impact to
BPA will flow through to NRU members via power
rates or system reliability. Further, depending on
where the point of compliance is, NRU members will
be reliant on BPA to meet those obligations on their
behalf.
- The SC appreciates the interest and importance of governance and
point of compliance to stakeholders and intends to discuss this
further in a technical workshop.
Stakeholder Engagement
- Emphasize the need to continue in-depth
stakeholder engagement to ensure broad
understanding and input into key decisions in Phase
2B.
- BPA will need to engage its customers and discuss
potential participation in the RA Program and how
this will impact it customers.
- The SC intends to continue in-depth stakeholder engagement in
Phase 2B.
- The SC acknowledges the importance and impact of Bonneville
Power Administration’s (BPA) participation in the future program on
its customers. Our understanding is that BPA is actively engaging its
customers on its future participation and plans to continue to do
through the detailed program design phase.
Program Interaction with Current and Planned Regional
Market Initiatives
- The SC intends to discuss the topic of RA Program interaction with
current and planned regional market programs and initiatives in a
SAC technical workshop.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 203 of 254
Stakeholder Comments Steering Committee (SC) Response
- Supports further exploring this topic, for example,
would the energy associated with “pooled capacity”
be able to be offered into the EIM?
- The PA will evaluate potential need for pooled capacity in the day-
(or days-) ahead timeframe and release any pooled capacity
determined not necessary for regional reliability. When that capacity
is released back to participating entities, they would be free to utilize
that unneeded capacity in transactions (e.g., the EIM) as they see fit.
- Further technical discussions with the SC and the PD will determine
the day ahead and real-time planning requirements and outline the
role of the PA in this time horizon. This would include how
Participants will be assessed as being compliant during the
operational timeframe, which may involve metrics that take into
account actual operational conditions. Within the day ahead and
real-time windows, member entities also participate in various
existing wholesale bilateral and organized markets (e.g., EIM). In
Phase 2B, the SC and PD will further consider how the operational
program design will integrate with these markets, including the
potential overlay between RA and RS metrics in the day ahead
timeframe.
Governance
- Governance is a key topic for NRU members, look
forward to actively participating in future
discussions on this topic.
- Recommend that most aspects of the non-binding
program ought to mirror the goals of the binding
program, including the independence of the PA.
- The SC appreciates the interest and importance of governance of
the program to stakeholders and intends to discuss this further in a
technical workshop.
Western
Interstate
Energy Board
General Remarks
- A regional RA Program is needed to (1) ensure
reliability, (2) deliver investment cost savings to
LSE’s and their customers, (3) respect state and local
autonomy over investment decisions.
- The Conceptual Design document is a good start to
developing a successful program.
- Thank you for this comment.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 204 of 254
Stakeholder Comments Steering Committee (SC) Response
Capacity RA Program
- It is reasonable to first design a capacity RA
Program and consider Energy RA and Flexibility RA
after and the staged implementation of the
program.
- It is unclear what is meant by a “less formal
mechanism” to access pooled resources prior to
Stage 3 (see p. 10).
- The staged implementation of the capacity program currently
anticipates Stage 1 would be a non-binding forward showing
program, Stage 2 would be a binding forward showing program,
and Stage 3 would add an operational program to the binding
forward showing program. Further consideration is necessary to
determine how the binding forward showing program could be
implemented in Stage 2 without a full operational program in place
to ensure that pooled capacity is accessible by all Participants. In
summer 2020, the Resource Adequacy Program Development
Project (RAPDP) Participants implemented an interim solution to
match entities experiencing exceptionally high loads (P99 loads) with
entities with surplus capacity available on the day ahead basis using
manual processes. Further consideration is necessary as part of
Phase 2B and the Phase 3 implementation plan, as to whether this
manual interim solution (“less formal mechanism”) is sufficient to
enable the binding forward showing to proceed while the full
operational solution is implemented, or whether additional steps
should be taken to bolster this (or another) solution as part of Stage
2.
Showing and Compliance Timeline
- Transparency and visibility are crucial to establishing
a Forward Showing Program that is trusted by all
stakeholders. Additional considerations for the
Detailed Design of Phase 2B are:
- At what level of granularity will the PA publish the
results of the compliance showing for the region
and the program Participants?
- When will the PA publish the results of the
compliance showing; prior to the cure period, after
the cure period, or both?
- The SC agrees that transparency and visibility are essential to
establishing a program trusted by all stakeholders.
- The SC appreciates the additional considerations/questions raised
regarding how the PA will make data available publicly. As noted
above, the SC agrees that transparency is important and expects
that the PA will make aggregate data available, where possible, to
communicate program results to stakeholders once the RA Program
is operational. This level of detail and timing of the release of data
has not yet been determined but will be considered and determined
later in the process when the PA is hired.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 205 of 254
Stakeholder Comments Steering Committee (SC) Response
- When will the PA publish the “CONE Factor” for
establishing the non-compliance penalty; prior to
the cure period, after the cure period, or both?
Regional Metrics
- The “perfect capacity” approach to separating the
“load” side of the RA evaluation from the “resource”
side of the evaluation is important to establishing a
transparent program that is fair and unbiased. Using
the probabilistic analysis to determine the planning
reserve margin for the region and program
Participants is reasonable and appropriate.
- Use of the PA’s load forecasts with a dispute
resolution process is likely the most efficient means
of obtaining unbiased and accurate load forecasts.
- Consideration of what data, information or submittal
would be made available to the public (page 18)
should include data elements that inform both the
“load” side and “resource” side of the RA
evaluations.
- It is not clear what is meant by “…participating
entities may need to change their market activities
to accommodate showing standards...” (page 18)?
Current market activities follow stringent risk
management procedures. The SC indicate how LSE
market activities may need to change to
accommodate the showing standards. Will LSEs
need to change their risk management procedures?
Are the anticipated changes likely to increase LSE
net variable power costs?
- The SC appreciates your support for the perfect capacity approach,
as well as considerations related to the proposed load forecasting
approach. Load forecasting methodology will be a topic for further
discussion in Phase 2B. The SC recognizes the importance of
accurate load forecasts and firm resource commitments in order to
determine adequacy and ensure reliability.
- It is generally anticipated that some aggregated information related
to regional load and resources will be made publicly available
through this program, but the Phase 2B detailed design and
discussions with the PA in implementation will further refine
recommendations for data sharing going forward. Thank you for
noting your specific consideration for both load and resource
information.
- With respect to market activities, in today’s markets, entities may
wait until a few months, weeks or even days ahead of the operating
day to purchase the energy required to meet their load plus other
obligations with no regionally agreed on requirement to meet a
Planning Reserve Margin (PRM). To comply with the RA Program in
the future, entities will be required to contract for capacity and
transmission in the forward showing time horizon (5+ months in
advance of the season) to meet the RA metrics.
- Net variable power cost increase or decrease is expected to be an
indicator of regional RA providing appropriate price signals to direct
investment.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 206 of 254
Stakeholder Comments Steering Committee (SC) Response
Penalty for Non-Compliance
- Using a “CONE Factor” to scale the size of the non-
compliance penalty to the size of the region’s actual
reserve margin is reasonable and appropriate. More
information about the rationale for the thresholds of
the “CONE Factor” would be helpful. A region that
meets its Planning Reserve Margin by more than 8
percent is arguably overbuilding capacity, why is a
CONE Factor of 125% appropriate (see page 24)?

- The SC’s use of the CONE factor as a penalty is intended to strongly
motivate Participants to comply with program metrics in the forward
showing time horizon. The CONE Factor used in the penalty
calculation is intended to decrease as the percentage of capacity
above the PRM increases (exact increases will be reviewed as part of
Phase 2B). The logic is that the penalty is lower when there is less
risk for failure and higher when there is more risk for failure. The
thresholds do not assume the region will or should achieve a certain
percentage above the PRM. These particular percentages are those
utilized in Southwest Power Pool’s (SPP) program, which was used as
a template (with a similar approach to penalties and compliance
design elements); their appropriateness and the logic behind
proposed factors will be considered in collaboration with the PA.
-
Accessing Pooled Capacity
- More discussion of the equation for the proposed
“triggering event” for accessing pooled capacity is
needed. It is not clear from the proposed equation
that the LSE is necessarily short capacity (e.g., the
equation does not include market activities).
- More explicit metrics and equations will be developed for many of
these situations (e.g., accessing pooled capacity) as part of Phase 2B.
Generally, the intent is to allow a Load Serving Entity (LSE) access to
pooled capacity if their actual load (+ extenuating circumstances like
net Variable Energy Resource (VER) production) is higher than was
planned for in the forward showing stage. An LSE may have the
option to use the market to meet their needs rather than accessing
the pooled capacity, though the logistics of access will be
considered further in Phase 2B.
Legal and Regulatory Considerations
- It is not clear from the discussion which functional
elements of an RA Program trigger FERC jurisdiction;
is it the implementation of non-compliance
penalties, the implementation of an operational
program, or both?
- It is also not clear if the FERC “public utility” and
“independence” requirements are separable (see
page 31). In other words, could the PA meet the
FERC “independence” requirement, and contract
- The “trigger” for FERC jurisdiction arises, fundamentally, by the
creation of a binding regional compact to share diversity benefits.
Penalties and operations are specific areas where FERC would assert
jurisdiction to ensure the program produces just and reasonable
results.
- Once a binding RA Program is established its PA will likely be
considered a public utility by definition under the Federal Power Act.
Because the services it would be providing in a binding setting could
create economic impacts or reliability impacts on market
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 207 of 254
Stakeholder Comments Steering Committee (SC) Response
with a separate entity that performs the functions
that trigger the “public utility” requirement?
Participants, the FERC rules prescribe that the public utility must
operate independently from any of the other market Participants to
ensure a level of fairness in the administration of the market.
- The specific functions to be performed in administration of the
forward showing and operational programs, and the roles and
responsibilities of the associated governing and administration
bodies, will be further discussed as part of Phase 2B.
Oregon
Citizens Utility
Board
General Remarks
- CUB supports an RA Program that meets the
reliability needs of the region in a manner that
optimizes existing resources—while providing for
necessary new resources—and leads to cost savings
for customers.
- Thank you for the comment.
RA Program Goals and Objectives
- Cost savings are only likely to be realized if the RA
Program is designed in a manner that is transparent.
CUB supports the inclusion of “transparency across
the program” as an objective to help promote an
efficient and fair RA Program, as articulated in the
joint comments by Renewable Northwest and the
NW Energy Coalition.
- CUB also supports the distinction made by WRA
between the role of the PA versus the role of
program oversight and evaluation.
- CUB believes this preliminary inventory and
subsequent determination of capacity contributions
is paramount.
- Thank you for the comment. The SC agrees that transparency is
important and expects that the PA will make aggregate data
available, where possible, to communicate program results to
stakeholders once the RA Program is operational. This level of detail
has not yet been determined but will be considered and determined
later in the process when the PA is hired.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 208 of 254
Stakeholder Comments Steering Committee (SC) Response
Forward Showing Program Conceptual Design
- Although certain elements of the program are likely
to—and arguably should—remain voluntary in
nature, CUB believes the inclusion of LSEs in the
program can provide a number of benefits. It would
not be helpful to regional reliability if LSEs were left
out of the RA Program, as it would create an
incentive for customers to leave utility service for
direct access in order to avoid paying the costs of
reliability.
- Thank you for the comment. The SC agrees that in order for
reliability to be adequately supported, RA needs to broadly
encompass load service in the footprint of the program.
- The SC appreciates the interest and importance of the governance
of the program and point of compliance in particular and intends to
discuss this further in a technical workshop.
Regional Adequacy Objective
- CUB supports the SC’s recommendation to include
an LOLE objective of 1 day in 10 years where
capacity is expected to be insufficient to meet load
plus contingency reserves.
- Thank you for this comment.
PRM
- As the details of the RA Program are being
considered by the SC and SAC members, leveraging
the benefits of the program to lower the PRM
should be top of mind.
- In order to reach a place in which we can consider
lowering the PRM, an accurate accounting of all
available capacity must first be taken. CUB agrees
with RNW and NWEC (page 27) that a more
granular and probabilistic approach is likely
necessary to evaluate intra-seasonal fluctuations
due to factors like climate change and
electrification.
- The program design is intended to optimize the benefits to all
participating entities and take advantage of the diversity in loads
and resources across the footprint of the program. An inherent
benefit of regional RA is lower overall cost to achieve the same level
of reliability that would be possible under individual utility planning
for RA. The realization of investment savings is one of the program
objectives identified by the SC. The benefits of increased reliability
and lower costs and risks will benefit the region as a whole.
- The program will accurately account for all loads and resources on at
least a monthly granularity in the forward showing program. Factors
like climate change and electrification will be accounted for in
entities’ load profiles that will change as conditions change.
Resources that experience impacts from variable weather patterns
will be considered for monthly qualifying capacity contribution
values to ensure this variability is appropriately managed.
Load Forecasting for Forward Showing
- CUB agrees with RNW and NWEC that load
forecasting methodologies should be consistent
- As noted in the question and 2A Conceptual Design (CD), the SC
recognizes the need for consistent and accurate load forecasting in
order to ensure reliability and RA. Phase 2B design work includes
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 209 of 254
Stakeholder Comments Steering Committee (SC) Response
with existing integrated resource planning and
should provide an integrated program forecast
rather than rolling up the forecasts of participating
entities.
further consideration of load forecasting and integration with
entities’ existing planning processes.
- With respect to Integrated Resource Plans (IRPs), the RA Program
will not replace the 10-year out IRP process, but will provide a more
accurate and up-to-date view in the 1- to 3-year window prior to the
operating year.
Regional Import/Export Assumptions
- CUB agrees with RNW and NWEC that additional
analysis on how this program will operate within the
construct of a regional day ahead market is
necessary.
- The SC intends to discuss the topic of RA Program interaction with
current and planned regional market programs and initiatives in a
technical workshop.
Resource Eligibility and Qualification
- CUB agrees with WRA that the treatment of
demand-side resources merits consideration in the
program’s design. Demand response (DR) has been
identified as a significant capacity resource for the
region.
- Because DR programs take time to develop and
require the recruitment of customer participation,
identifying how DR participate should be an early
priority because it is likely to affect DR program
design.
- The SC agrees that treatment of demand-side resources is an
important element of the program, and this will be further discussed
with the advisory committee in Phase 2B.
Randy Hardy,
IPP Consultant
General Remarks
- Overall, the Conceptual Design is excellent. The SC
has laid out a well-structured program which
addresses most, if not all, of the components of a
robust, viable RA Program.
- Focusing RA standards on critical hours during
binding seasons is particularly important.
- Thank you for this comment.
Dry Water Years - The SC recognizes that there can be challenges associated with
prolonged low water conditions in the region, and as part of Phase
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 210 of 254
Stakeholder Comments Steering Committee (SC) Response
- Very concerned that the current RA Conceptual
Design does not address the potential effect of dry
water years on the NWPP hydro capacity
contribution to meeting RA standards.
- Based on our discussion at the August 21 SAC
meeting, it is my understanding that NWPP SC will
re-examine this issue to determine the capacity
contribution of PNW hydro in dry water years in
critical hours.
- Appreciate that dry water is an energy and not a
strict capacity issue, and that fully incorporating this
effect into a capacity RA Program would both
greatly complicate RA Program design and lengthen
the timeframe to deliver a final RA Program. What I
expect, however, is that we can make some rough
intuitive RA standards adjustments to try to account
for this phenomenon. Perhaps the SC could simply
increase the PRM you would otherwise calculate by
2-3 percentage points to account for these potential
impacts.
2B’s detailed design, will work to evaluate the impact a low water
scenario might have on the hydro storage capacity capability during
capacity critical hours, the hours within a day where the delta
between forecasted net load and generation is the smallest, to
determine if changes to the RA requirements should be made.
Imports/Exports
- This area is especially important to ensuring a
comprehensive RA Program, and I basically agree
with the way the SC is addressing it. Again, focusing
on the critical hours when imports are needed, and
how many megawatts can be provided during those
hours from outside the NWPP footprint, is key to
designing a successful program. In this
regard, averages, whether annual, season on
monthly, are the enemy of accurate reliability
planning in general and RA Programs in particular.
- Historically, the NWPCC and PNW utilities have
assumed a constant 2,500MW of CA imports are
- Thank you for this comment. The SC agrees that the assumptions
made about what can be counted on from external regions during
capacity critical hours must be carefully considered.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 211 of 254
Stakeholder Comments Steering Committee (SC) Response
available (to NWPP) throughout the winter.
However, as SC members have pointed out, even in
winter months CA is likely constrained from hours
16 to 22 on a typical day given the state's ever-
increasing reliance on solar. If these hours fall into
the critical category during the NWPP binding
winter season, then counting on 2,500MW from CA
(or possibly any imports during this period) is
probably not prudent.
Montana
Energy Office
Qualifying Capacity
- Agree with the SC recommendation that the
qualifying capacity of wind resources be evaluated
zonally across the Pacific Northwest.
- Recommend that the Committee more thoroughly
evaluate the implications of zonal quantification of
capacity for solar resources.
- We agree with the SC that a methodology needs to
be created for calculating the capacity contribution
of various demand-side management (DSM)
resources. Recently, California relied on DSM to
minimize and, in some circumstances, avoid rolling
blackouts during a period of sustained and
widespread hot weather, underscoring its
importance in maintaining reliability.
- Thank you for your comments. The SC agrees that VER qualifying
capacity contribution should be evaluated zonally across the
program footprint. The SC also agrees that treatment of demand-
side resources is an important element of the program, and this will
be further considered and discussed with the SAC in Phase 2B.
Governance
- Recommend providing additional clarity concerning
regarding what a Balancing Authority’s responsibility
would be for ensuring resource adequacy for choice
customers/load serving entities inside their
Balancing Authority Area. For example, would load
serving entities be responsible for participating
independently in this RA Program, and ensuring
- Thank you for the comment. The SC looks forward to further
discussing the question of point of compliance with stakeholders in
Phase 2B. The SC agrees that in order for reliability to be adequately
supported, RA needs to broadly encompass load service in the
footprint of the program. There will be a technical workshop on
governance.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 212 of 254
Stakeholder Comments Steering Committee (SC) Response
their own adequate supply, or would this
responsibility fall to the BA?
Program Interaction with Current and Planned Regional
Market Initiatives
- The NWPP RA Program should clarify how the
program will interact with the regional Reliability
Coordinator and evolving energy imbalance
markets. This coordination should aim to reduce
redundant services and functions of each entity. It
should also align the resource planning
requirements or standards of each
program/service/market.
- The SC intends to discuss the topic of RA Program interaction with
current and planned regional market programs and initiatives in a
technical workshop.
- Further technical discussions with the SC and the PD will determine
the day ahead and real-time planning requirements and outline the
role of the PA in this time horizon. This would include how
Participants will be assessed as being compliant during the
operational timeframe, which may involve metrics that take into
account actual operational conditions. Within the day ahead and
real-time windows, member entities also participate in various
existing wholesale bilateral and organized markets (e.g., EIM). In
Phase 2B, the SC and PD will further consider how the operational
program design will integrate with these markets, including the
potential overlay between RA and RS metrics in the day ahead
timeframe.
Program Participation/Eligibility
- The NWPP RA Program should clarify how
independent generators (non-utility owned
resources, QFs, independent brokers) fit into the
program. Would they be treated like utility-owned
resources if a utility has contracted for their supply
for a particular operational season?
- We recommend that NWPP provide a general
resource planning template to RA Program
Participants that would help integrate this RA
Program with the resource planning processes of
utilities involved.
- The RA Program design should clarify what recourse
or action, if any, a load-serving entity has to take to
avoid a penalty if between the end of a curing
- The SC recognizes the importance of ensuring all resources
(including independent generators) are able to contribute to the
program. In Phase 2B, the SC will work through additional resource
eligibility questions and contracting requirements; this will be done
with consideration of market liquidity and program rigor. Generally,
the design will need to ensure all resources (utility-owned, non-
utility owned, qualifying facilities (QFs), etc.) meet the same
standards for reliability. The SC will further clarify how independent
generators fit into the program in Phase 2B.
- In Phase 2A, the SC developed an excel workbook to enable utility
stakeholders to better understand the mechanics of the forward
showing process. The workbook is intended to help stakeholders
build intuition about possible impacts on their utilities. The
workbook is available for public download on the Northwest Power
Pool (NWPP) website.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 213 of 254
Stakeholder Comments Steering Committee (SC) Response
period and the subsequent operational season a
generator unexpectedly goes offline. Conversely, if
the LSE acquires an asset after the curing period,
can that asset still be used in the following
operational season?
- The SC will further clarify rules related to the transition between the
forward showing and operational portion of the program, resource
replacement requirements, and operational program procedures in
Phase 2B.
AWEC General Remarks
- We are encouraged by the quality of work done
during Phase 2A and the good-faith, collaborative
spirit shown by various stakeholders throughout the
Resource Adequacy Program Development Project
(“RAPDP”) process. It is important that at least one
independent power producer has joined the SC
effort to ensure a diversity of voices are present
amongst the ultimate decision-making body.
- An acceptable RA Program should not drive up the
cost of reliability. Further, whether energy or
capacity are used to measure and achieve RA
sufficiency, the cost should be less than it would be,
absent the regional framework.
- In the Southwest, there is no RA Program; however,
there is a contractually based regional reliability
program called the Southwest Reserve Sharing
Group. Has the SC contrasted the costs and benefits
of such solutions with the costs and benefits of a
more traditional RA Program, given the
complications caused by the lack of an organized
market?
- The SC values the perspective of stakeholders and expects to
continue to engage with them to ensure that diverse perspectives
are considered.
- As indicated in the CD, we expect that the binding phases of the
program will include a governance structure that addresses
independence and the opportunity for stakeholder engagement. The
SC appreciates the interest and importance of the governance of the
program and intends to discuss this further in a technical workshop.
- The program design is intended to optimize the benefits to all
participating entities and take advantage of the diversity in loads
and resources across the footprint of the program. An inherent
benefit of regional RA is lower overall cost to achieve the same level
of reliability that would be possible under individual utility planning
for RA. The realization of investment savings is one of the program
objectives identified by the SC. The benefits of increased reliability
and lower costs and risks will benefit the region as a whole.
- The Southwest Reserve Sharing Group is a program for sharing
contingency reserves to respond to forced outages and other
emergency conditions, similar to the NWPP’s Reserve Sharing
Program. This differs from programs such as the NWPP RA Program
effort, which focuses on ensuring that members are planning in
advance for adequate capacity to meet load during capacity critical
hours. In the 2A effort, the SC worked to pull as many relevant best
practices as possible while discussing program CD, reviewing similar
RA Programs from across North America (especially focused on SPP
and California Public Utilities Commission (CPUC) RA Programs).
Governance/Point of Compliance - Thank you for the comment. The SC agrees that in order for
reliability to be adequately supported, RA needs to broadly
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 214 of 254
Stakeholder Comments Steering Committee (SC) Response
- Participation in the RA framework by Energy Service
Providers/Energy Service Suppliers (“ESPs”) is critical
to ensure the efficient operation of direct access
programs in various states. Likely this means that
the initial leaning toward load serving entity level
participation is preferable. In the case of a Balancing
Authorities level participation, mechanisms to
coordinate ESP RA with the local BA showing and
reporting will be necessary in order to ensure that
customers purchasing RA from their ESPs are not
required to also pay for BA-owned or acquired RA.
- Because of the prominence of Bonneville Power
Administration in the Northwest, it is critical that
LSEs and large customers within BPA’s footprint
understand how, or if, BPA will participate in this
framework and how it will pass along the RA costs
or benefits to its utility customers, should the
Agency participate.
encompass load service in the footprint of the program. If LSEs
become the point of compliance for RA, then it is important to
address how Energy Service Providers/Energy Service Suppliers
(ESPs/ESSs) also participate in RA. The SC looks forward to further
discussing the question of point of compliance with stakeholders in
Phase 2B during the technical workshop on governance.
- The SC acknowledges the importance and impact of BPA’s
participation in the future program on its customers. Our
understanding is that BPA is actively engaging its customers on its
future participation and plans to continue to do so through the
detailed program design phase.
Program Interaction with Current and Planned Regional
Market Initiatives
- The way in which the NWPP RA Program
“coordinates” with the EIM—especially if BPA joins
the EIM—or how the NWPP RA Program creates a
back-up system to access pooled resources must
also be explored. This area is fundamental to
unlocking the diversity benefits and related, the
purposed program cost savings.
- The SC intends to discuss the topic of RA Program interaction with
current and planned regional market programs and initiatives in a
technical workshop.
- Further technical discussions with the SC and the PD will determine
the day ahead and real-time planning requirements and outline the
role of the PA in this time horizon. This would include how
Participants will be assessed as being compliant during the
operational timeframe, which may involve metrics that take into
account actual operational conditions. Within the day ahead and
real-time windows, member entities also participate in various
existing wholesale bilateral and organized markets (e.g., EIM). In
Phase 2B, the SC and PD will further consider how the operational
program design will integrate with these markets, including the
potential overlay between RA and RS metrics in the day ahead
timeframe.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 215 of 254
Stakeholder Comments Steering Committee (SC) Response
Capacity RA Program
- Additional information behind the choice to begin
with a capacity RA Program would be appreciated.
Additionally, an understanding of what it would look
like to build an energy or flex RA on top of the
capacity framework would be helpful.

- The SC identified capacity RA as the most urgent need facing the
region. Further, though its implementation presents a number of
challenges, a capacity adequacy program is the most straightforward
to implement.
- The capacity RA Program will address the needs of the region in the
capacity critical hours, the hours within a day where the delta
between forecasted net load and generation is the smallest. Once
the capacity program is implemented, the SC will explore whether
there are other solutions that could build upon this program, such
as an energy adequacy standard. Further, the SC recognizes that
there can be challenges associated with prolonged low water
conditions in the region, and in Phase 2B, will work together to
evaluate the impact a low water scenario might have on the hydro
storage capacity capability during capacity critical hours to
determine if changes to the RA requirements should be made. This
topic will be further addressed a SAC technical workshop.
Program Objectives
- According to Section 1.4.2 of the Conceptual Design
Document, the RA Program will support nine
Objectives, including the following: “[e]nsure that
the participation, evaluation, and qualification of
resources is technology neutral.”24/ Please identify
what is meant by “technology neutral.”
- The term “technology neutral” is intended to convey that the
qualifying capacity contribution of resources will be determined
based on the resource’s contribution to regional reliability during
capacity critical hours, the hours within a day where the delta
between forecasted net load and generation is the smallest. The
intent of the program is not to exclude any resource types that
members may choose to meet their requirements, but rather to
appropriately accredit capacity based on the operating
characteristics of the resource.
Capacity Contribution
- A large number of industrial and commercial
customers within the likely footprint of the NWPP
RA Program operate cogeneration resources. It is
- The SC recognizes that some cogeneration resources can and do
contribute to RA. However, each situation can vary depending on
the type of resource, operating characteristics, and dispatch control.
Some cogeneration resources may be suited to contributing in the

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Stakeholder Comments Steering Committee (SC) Response
important to understand: 1) how or should these
customer-owned resources be accounted for and
remunerated for their capacity contributions; and 2)
what metric for qualifying capacity would be
assigned to cogeneration technology?
same manner as traditional generation resources, while others may
be more suited to contributing as a peak load reduction. Any
compensation for the capacity of a cogeneration resource would be
a commercial arrangement between the generator and the entity
claiming it as part of its capacity portfolio.
PPC General Remarks
- Exploration of a potential RA Program for the NW
could be a timely solution to address an impending
regional capacity shortage.
- Success of an RA Program directly depends on how
it is designed and implemented.
- Continued engagement of the SAC and other
stakeholders is important.
- Supports the creation of smaller work groups open
to SAC members to provide additional opportunities
to explore more of the technical details of the
program.
- Requests that all comments submitted on the CD be
shared with members of the SAC, along with any
summaries of those comments provided to the SC.
- The SC plans to continue to actively engage in the SAC in Phase 2B.
In addition to the half-days meeting which have been held
approximately quarterly, we plan to hold a series of technical
workshops on topics of interest shared by SAC members.
- All comments submitted on the CD document will be shared with
the SAC, in addition to this summary matrix of comments and SC
responses.
Program Structure
- Supportive of the proposed structural that is
voluntary, and technology neutral design is
important as well.
- Supports proposed capacity forward-showing
program with two binding seasons appears to be a
good starting point for the program.
- Thank you for this comment.
Hydro Capacity Contribution - Hydro capacity contribution will be addressed in a SAC technical
workshop.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Stakeholder Comments Steering Committee (SC) Response
- Supports the SC’s work to develop a hydro model
that will work for the Northwest. PPC requests that
this be added to a SAC technical workshop.
Governance
- There is little information in the CD on governance.
Requests that the SC prioritize making additional
information available to the SAC regarding
governance structures under consideration, for
example analysis conducted to-date on FERC
jurisdictional elements of the program.
- The outstanding question of point of compliance
leaves uncertainly for many PPC members on their
potential role in the program. The SC should strive
to clarify this question as soon as possible.
- Impacts of the program on PPC members will be
largely dependent on policy decisions BPA makes to
implement the program.
- The SC appreciates the interest and importance of the governance
of the program and point of compliance in particular and intends to
discuss this further in a technical workshop.
- The SC acknowledges the importance and impact of BPA’s
participation in the future program on its customers. Our
understanding is that BPA is actively engaging its customers on its
future participation and plans to continue to do through the
detailed program design phase.
NWEC Program Scope
- Suggest that NWPP include a statement of scope in
the next round of program documents. Is the third
phase of the program addressing capacity, but
energy and flex RA could be addressed in the
future?
- The SC identified capacity RA as the most urgent need facing the
region. Further, though its implementation presents a number of
challenges, a capacity adequacy program is the most straightforward
to implement.
- The capacity RA Program will address the needs of the region in the
capacity critical hours, the hours within a day where the delta
between forecasted net load and generation is the smallest. Once
the capacity program is implemented, the SC will explore whether
there are other solutions that could build upon this program, such
as an energy adequacy standard. Further, the SC recognizes that
there can be challenges associated with prolonged low water
conditions in the region, and in Phase 2B, will work together to
evaluate the impact a low water scenario might have on the hydro
storage capacity capability during capacity critical hours to
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Stakeholder Comments Steering Committee (SC) Response
determine if changes to the RA requirements should be made. This
topic will be further addressed a SAC technical workshop.
Hydro Capacity Contribution
- Concerned with the issue of low hydro seasons and
how the program assessment, PRM and other
aspects of the program will accommodate that
possibility.
- The SC recognizes that there can be challenges associated with
prolonged low water conditions in the region and will work together
to evaluate the impact a low water scenario might have on the hydro
storage capacity capability during capacity critical hours to
determine if changes to the RA requirements should be made.
Hydro capacity contribution will be addressed in a SAC technical
workshop.
Alignment with State Regulation and Policy
- Recommends further development of the RA
Program should explicitly include coordination with
state and provincial regulators and agencies, so that
the program aligns with existing policies and
processes such as integrated resource planning.
- The SC has begun to conduct state outreach and intends to continue
such outreach throughout the program’s development.
Alignment with Western Market Development
- Urges NWPP to align the RA Program with other
market developments in the Western
Interconnection, especially the existing Western
Energy Imbalance Market and the proposed
Enhanced Day Ahead Market.
- The SC intends to discuss the topic of RA Program interaction with
current and planned regional market programs and initiatives in a
technical workshop.
- Further technical discussions with the SC and the PD will determine
the day ahead and real-time planning requirements and outline the
role of the PA in this time horizon. This would include how
participants will be assessed as being compliant during the
operational timeframe, which may involve metrics that take into
account actual operational conditions. Within the day ahead and
real-time windows, member entities also participate in various
existing wholesale bilateral and organized markets (e.g., EIM). In
Phase 2B, the SC and PD will further consider how the operational
program design will integrate with these markets, including the
potential overlay between RA and RS metrics in the day ahead
timeframe.
Standard Products to Facilitate RA Showing - Procurement and acquisition related to both the forward showing
time horizon and the operational program will be further explored in
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Stakeholder Comments Steering Committee (SC) Response
- NWEC recommends that the RA Program include an
acquisition component to facilitate the RA showing
process by developing standard products and
reporting, rather than simply leaving that to existing
“market structure,” which at this point involves a
purely ad hoc approach.
- An exchange component in the program design
might include: (1) a pro forma contract similar to the
WSPP Inc. Agreement; and (2) a “bulletin board” or
other mechanism to record requests, offers and
agreements.
Phase 2B and the suggestions noted here have been identified for
future discussion.
Accelerate Uptake of Flexible RA Resources
- NWEC believes the key learning from the events of
the last month in California is that rapid uptake of
flexible resources is essential to meeting RA needs
in this time of dramatic change.
- The most important thing that the RA Program can
do to achieve rapid uptake of these important and
widely available resources is to ensure that the
accreditation and counting rules for flexible
resources, including storage, demand response,
microgrids, etc., are comparable and fair alongside
supply resources.
- The SC agrees that it is important to ensure counting rules for all
resources, including for flexible resources are fair and will be
performing additional work on this topic in Phase 2B and discussing
with the advisory committee further.
- It is a key RAPDP objective to ensure that the regional RA Program
be technologically neutral and designed to not exclude any resource
types that members may choose to meet their requirements, but
rather to appropriately accredit capacity based on the operating
characteristics of the resource.
Compliance and Penalties
- NWEC is not comfortable with the use of the Cost of
New Entry concept as traditionally applied, whether
for compliance penalties or other purposes. The
reference plant construct is not suitable for
determining overall system value, whether based on
a gas plant or any other resource type, especially as
the resource base becomes more diverse and
complementary, because all resources have
- Thank you for your comments; we will consider these as we move
forward with program design in Phase 2B.
- The SC’s use of the CONE factor as a penalty is intended to strongly
motivate Participants to comply with program metrics in the forward
showing time horizon. The CONE Factor used in the penalty
calculation is intended to decrease as the percentage of capacity
above the PRM increases (exact increases will be reviewed as part of
Phase 2B). The logic is that the penalty is lower when there is less
risk for failure and higher when there is more risk for failure. The
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Stakeholder Comments Steering Committee (SC) Response
limitations and their value is context dependent, in
addition CONE does not follow cost causation.
thresholds do not assume the region will or should achieve a certain
percentage above the PRM. These particular percentages are those
utilized in SPP’s program, which was used as a template (with a
similar approach to penalties and compliance design elements); their
appropriateness and the logic behind proposed factors will be
considered in collaboration with the PA.
Stakeholder Input
- NWEC urges the NWPP to formalize a stronger and
deeper approach to stakeholder input, not only
during the forthcoming Phase 2B design period but
going forward into program implementation.
- The SC agrees that stakeholder input is essential to the RA Program
development and future stakeholder engagement may evolve into a
more formal process as we get closer to implementation and after
the PA is hired.
Adaptive Management
- NWEC suggests that NWPP follow a course of
adaptive management in program design and
implementation.
- In particular, recommends that a program
evaluation of the first pre-binding phase of the
program, including both process and impact
assessments, be conducted by an outside evaluator,
so that the binding phase of the program can gain
the benefit of formal external review.
- Thank you for your recommendation. Further discussion on
implementation plans and roles/responsibilities for the PA and/or
Program Evaluator/Monitor are planned as part of Phase 2B. These
suggestions have been flagged for further discussion as the
transition from the non-binding Stage 1 to binding Stage 2 is
considered.
NIPPC General Remarks
- Supports the creation of a well-designed RA
Program in the Northwest.
- Welcomes the addition of Calpine to the SC as this
addition brings a more diverse commercial
perspective.
- Thank you for this comment.
Stakeholder Engagement
- Supports proposal of holding technical workshops
with the SAC, transmission deliverability and RA
contracting practices are most important to address.
- Thank you for this comment. The SC intends to address transmission
deliverability, RA contracting practices, and interplay with Extended
Day ahead Market (EDAM)/EIM in technical workshops and will
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Stakeholder Comments Steering Committee (SC) Response
- Workshops on transmission deliverability should
cover details of the zonal transmission requirements
and how entities with RA obligations could acquire
transmission rights in order to access the
geographic diversity benefit.
- Workshops on contracting practices should
encompass a more detailed discussion of function
of operational component of the program and
interplay with EDAM.
consider the recommendations for specific details the workshops
should cover as we develop the meeting agendas.
Two Binding Seasons/Commitment Periods
- NIPPC remains concerned that seasonal approach to
commitment periods may disadvantage IPP
generators that do not have ratepayer cost recovery
recourse.
- The cost of procuring capacity under a seasonal
requirement is likely to lead to higher RA prices than
under an annual requirement as all generators seek
to recover annual fixed costs under sub-annual
contracts, this may mitigate NIPPC’s initial concern.
- Opposes shortening the RA commitment periods
any further, recognizing that some LSEs prefer a
shorter, even monthly, RA obligation.
- Urges the SC to explore mechanisms to encourage
longer-term multi-year contracting for capacity,
noting that SPP’s RA Program has requirements that
encourage longer term capacity contracting.
- The stronger a signal from a regional program that
capacity will be adequately compensated over
multiple years, the more likely RA will be ensured.
- The SC had to balance the benefits and costs associated with
monthly, seasonal, and annual requirements. Currently, we are
looking at two binding seasons – one 5 month long and the other 4
months long. These seasons were selected based on when the
capacity critical hours, the hours within a day where the delta
between forecasted net load and generation is the smallest,
occurred. The length of these seasons may change if the modeling
shows the capacity critical hours in longer or shorter seasons. Also,
these seasons may change as loads, resources, and/or regulatory
requirements change.
- In general, the seasons need to be long enough to take advantage
of the load/resource diversity which should also lower the PRM.
Another factor that needs to be considered is the impact on planned
outages. We understand that in other RA Programs, generators take
all of their planned outages in the non-binding seasons to optimize
value.
Contracting Paradigm - Thank you for this comment. The SC intends to address RA
contracting practices/paradigm in a technical workshop and will
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Stakeholder Comments Steering Committee (SC) Response
- Urges the SC to explore in more detail with the SAC
and SC members how the contracting paradigm in
the region may shift with a regional RA Program.
Suggests that SC provide a quantitative analysis (in
an aggregate fashion) of existing contracting
practices in the region for capacity which should
ideally disclose the amount of capacity required by
LSEs from other parties in advance of real-time
operations and a break-out of the average terms of
those commitments in recent years.
- The SC should provide illustrative examples of the
actual form of an RA contract it envisions between
LSE’s and other parties.
- The mechanics of how a systems-triggering event
would impact day ahead and real-time transactions
that convert capacity resources into energy should
be more fully explored. For example, if regional RA
Participants also participate in EDAM, what potential
frictions points would exist? Would there be
restrictions on making bids into the EDAM while still
complying with an RA obligation?
- The SC should explore in detail how RA obligations
could be transferred among participating entities.
consider the recommendations for specific details the workshops
should cover as we develop the meeting agendas.
- As you know, in today’s markets, entities may wait until a few
months, weeks or even days ahead of the operating day to purchase
the energy required to meet their load needs. To comply with the RA
Program in the future, entities will be required to contract for
capacity and transmission in the forward showing time horizon (5+
months in advance of the season) to meet the RA metrics.
- The SC will consider, as part of Phase 2B, how contracted capacity
would demonstrate meeting program requirements and how
transfer of obligation would occur; we will consider your
recommendation for an illustrative example of those contracts as
those discussions progress.
- Similarly, the SC will be considering in much greater detail the
operational time horizon, systems-triggering events, and how
pooled capacity would be called upon. Phase 2B will specifically
consider integration with other ongoing regional programs,
including EDAM and EIM. The SC intends to discuss the topic of RA
Program interaction with current and planned regional market
programs and initiatives in a technical workshop.
Transmission
- Urges the SC to engage with a broader cross-
section of transmission customers in the region
regarding deliverability requirements.
- The proposed zonal approach creates an incentive
for transmission operators and customers alike to
secure transmission rights within constrained load
zones in order to access the geographic diversity
benefit of the regional program.
- Thank you for this comment. The SC will further evaluate
transmission deliverability in a technical workshop and will consider
these recommendations/comments provided.
- Also, we are coordinating with all of the Balancing Authorities (BAs)
participating in the program (including all of the critical transmission
providers) and with the Northern Grid transmission group. We will
use the input from these groups in addition to the SC members with
transmission to consider transmission constraints etc.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 223 of 254
Stakeholder Comments Steering Committee (SC) Response
- SC should evaluate whether zonal approach
conforms with OATT’s of the region’s transmission
operators.
- Encourages SC to discuss in more detail how a zonal
approach would shine a spotlight on transmission
constrains for planning purposes.
Governance
- Urges the SC to propose a specific way to ensure
the independence and adequate oversight of the PA
of the regional program.
- Recommends the SAC and SC evaluate the bylaws
of organizations like SPP who have similar RA
Programs approved by FERC.
- Recommends creation of an independent multi-
state regulatory board comprised of state regulatory
representatives with a meaningful oversight role
with a role for consumer owned utilities and PMA’s
as well.
- Thank you for these comments and recommendations. The SC will
hold a SAC technical workshop on governance.
- The SC and the external counsel retained for this effort have spent
significant time considering governance structures of FERC
jurisdictional programs. We continue to learn from their experiences,
pulling what we can to help us navigate our unique situation.
- Roles and responsibilities for governing groups will be further
considered as part of Phase 2B, and your recommendations for state
engagement have been identified for consideration as those
discussions progress.
Point of Compliance
- NIPPC supports establishing the RA obligation point
of compliance at the LSE level, however it notes that
that the Oregon PUC is currently exploring in
Docket UM 2024 how retail choice providers in
Oregon would participate in a regional RA Program
to meet state RA requirements as well as how a
state obligation could work in harmony with a
regional RA Program and anticipates more detailed
discussion on this.
- A regional RA Program open to all LSE’s is more
efficient means than a program limited to as single
state.
- Thank you for these comments. The SC looks forward to further
discussing the question of point of compliance with stakeholders in
Phase 2B. The SC believes that in order for reliability to be
adequately supported, RA needs to broadly encompass load service
in the footprint of the program. There will be a technical workshop
on governance.
- The SC has begun work on state outreach, which will continue
throughout Phase 2B. We are aware of the Oregon Public Utility
Commission’s (OPUC) RA docket and have provided updates on the
NWPP effort to the OPUC.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Stakeholder Comments Steering Committee (SC) Response
- LSEs should be obligated entities under a regional
program.
- Non-IOU LSE’s serving load within BAAs should be
able to choose to procure some of amount of RA
directly from the applicable BA to the extent such
amounts are available to serve both the BA’s native
load and nested LSE’s load.
- If RA obligations are imposed on retail choice
providers, states should make participation in the
regional program the primary and preferred means
of compliance.
Additional Questions and Clarifying Recommendations
Contingency reserves
- What is the expected interaction between the NWPP
Reserve Sharing Program for contingency reserves
and an RA Program during capacity critical hours?
- In complying with the RA Program, would LSEs be
able to testify to participation in the NWPP Reserve
Sharing Program to supply a portion of their RA
obligation?
- In that case, should explicit cross-participation in the
two programs be opened to and encouraged for a
broader array of market Participants?
Participation fees
- What is an appropriate possible range of fees for
program participation, both on the part of LSEs and
the part of generators and marketers? How do other
RA Programs assess fees to cover the costs of
running the programs?
Underperformance penalties
- The contingency reserve sharing program is usually available for
about 60 minutes during a declared system emergency. Because
these events can occur before, during or after capacity critical hours,
we expect that the RA capacity and contingency reserves will be
separate and distinct. The SC is actively considering this issue in
Phase 2B.
- The SC anticipates providing approximations for cost of participation
in the future program as part of Phase 2B deliverables, and
endeavors to have more answers to these questions when the phase
is complete.
- Similarly, the operational program and non-compliance or
underperformance in that time horizon will be considered during
Phase 2B.
- Stress conditions and reliability events will be a consideration in
Phase 2B.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Stakeholder Comments Steering Committee (SC) Response
- What is an appropriate possible range of financial
penalties to assess for underperformance or non-
performance of participating capacity resources in
the event that committed capacity is called on to be
converted to energy by a counterparty LSE or by the
PA under a systems-triggering event?
RA event simulations
- The SC should examine several illustrative RA stress
cases to simulate how the regional program may or
may not help avoid or mitigate severe stress
conditions, including region-wide reliability events.
Oregon PUC Staged Functionality of the Program
- It would be helpful if the CD explained what the
goal of each stage is after it's description.
- This is a helpful recommendation and in future documentation, the
SC will strive to include specific delineation of goals and objectives.
Capacity RA Program
- It seems reasonable that the RA resource sharing
part of the plan utilize the same analysis timeframe
as the forward showing. If the showing is for "RA"
(1-4 years) then the sharing portion should also be
on the 1–4-year timeframe.
- If the plan is for the RA sharing to be available on a
day ahead timeframe, then the forward showing
should have a corresponding timeframe.
- The ability of a regional RA Program to access diversity benefits
(a.k.a. “sharing”) occurs in both the forward showing program and
the operational program. The timeframes for the forward showing
program and the operational program are different, as are the
metrics that are used to evaluate whether a Participant has met all of
their requirements. The proposed timeframe for the binding forward
showing program is 7 months ahead of the winter and summer
season. The regional RA Program is also anticipated to provide
Participants with non-binding RA requirement information 2-3 years
ahead of the compliance period. The operational timeframe is
currently under consideration in Phase 2B. Further technical
discussions with the SC and the PD will determine the day ahead
and real-time planning requirements and outline the role of the PA
in this time horizon. Although different timeframes are involved with
these components of the program, diversity benefits are available in
each. The manner in which diversity benefits are identified and
accessed will differ in the forward showing program and the
operational program.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
Schedule 7, Page 226 of 254
Stakeholder Comments Steering Committee (SC) Response
- During the forward showing time period, the PA will determine the
PRM for the entire program footprint as a whole, assuming that the
footprint is coordinating its planning. The PA will also determine
each Participant’s sub-allocated PRM based on the footprint’s PRM.
In this manner, a Participant’s individual PRM may be lower (than it
would have been if an entity were attempting to meet the same
reliability metrics on its own) because of the RA Program footprint
diversity.
- The operational timeframe is where additional diversity benefits may
become “unlocked” through accessing pooled regional RA
resources, taking into account actual operational conditions
(something that cannot occur during the forward showing
assessment because the forward showing is a “snapshot” at a given
point in time). For example, it is possible that a Participant who met
all of its forward showing requirements at the forward showing
deadline enters the operational timeframe with insufficient capacity
based on operational conditions (e.g., because of forced outages,
etc.). Conversely, it is possible that a Participant who met all of its
forward showing requirements at the forward showing deadline
enters the operational timeframe with surplus capacity (e.g., because
of unexpected decreases in load due to weather changes, etc.).
Under this scenario, the Participants of the program should be able
to benefit from being part of the program; the Participant that is
short can share the surplus capacity of the Participant that is long.
- As explained above, further technical discussions with the SC and
the PD will determine the day ahead and real-time planning
requirements and outline the role of the PA in this time horizon. This
would include how Participants will be assessed as being compliant
during the operational timeframe, which may involve metrics that
take into account actual operational conditions. Within the day
ahead and real-time windows, member entities also participate in
various existing wholesale bilateral and organized markets (e.g.,
EIM). In Phase 2B, the SC and PD will further consider how the
operational program design will integrate with these markets,
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Stakeholder Comments Steering Committee (SC) Response
including the potential overlay between RA and RS metrics in the
day ahead timeframe.
Capacity Contribution of Resources
- ELCC and UCAP both only measure average or
expected values of capacity. These are fine for RA
timeframe analysis of raw capacity. However, these
metrics are not as predictive in a day ahead
paradigm and should not be relied on to be
accurate in any timeframe shorter than seasonal.
- Agree. Please see response above which addresses the different
timeframes and metrics used for the forward showing program and
the operational program. Metrics like Effective Load Carrying
Capacity (ELCC) and Unforced Capacity (UCAP) are only proposed to
be used for the forward showing program. The operational program
would utilize metrics that take into account actual operational
conditions.
Forced Outages
- I am not sure how ELCC handles forced outages -
these are somewhat normal events for VERs.
- Forced outages are already taken into account for ELCC because
ELCC looks at actual historical performance of the resource on an
hourly basis.
Transmission and Deliverability
- This may prove to be a pivotal aspect of the
program. Even if entities are generation rich, if
transmission is unavailable to move the energy, the
impact on RA is critical.
- It may turn out that a transmission sharing program
proves as valuable as a generation (capacity) sharing
program for RA purposes.
- Thank you for this comment. The SC will further evaluate
transmission deliverability in a technical workshop and will consider
these recommendations/comments provided.
Operational Program
- It appears to me incongruent to have a forward
planning program based on 1-4 year capacity
adequacy and then assume that there is an
operational timeframe adequacy in the day ahead
time period.
- This implies that perhaps ALL resources of a
participating entity will become "pooled." I assume
that an entity's requirement to serve native load
takes a priority over any RA sharing - there may be
conflicting asks of the same resource.
- The intent of the forward showing program is to ensure in the
planning horizon that there is sufficient capacity for the entire
footprint to serve load during capacity critical hours, the hours
within a day where the delta between forecasted net load and
generation is the smallest. In order to benefit from regional load and
resource diversity, program Participants will need to have some way
to share that diversity in the operating time horizon.
- In the forward showing program, participating entities must show
they have enough resources to fulfill regional reliability metrics;
resources they possess beyond these metrics are not subject to the
program unless contracted to another Participant to fulfill that
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Stakeholder Comments Steering Committee (SC) Response
- The approach to pooled capacity appears to suggest
that the ability for a company to dispatch its own
resources to meet its own reserve needs will be
superseded by the program. Will utilities be
comfortable giving up control of their pooled
resources in a crisis?
Participant’s metrics. It is only the resources used to meet those
metrics that are considered “pooled” capacity.
- The ability to access pooled capacity in the operational timeframe
will take into account actual operational conditions. Participating
entities will retain full control for dispatching their own resources.
Entities experiencing high load events will be expected to dispatch
the resources they used to meet the forward showing adequacy
metrics (or substitutes – for further discussion). Participating entities
not experiencing high load events would be responsible for making
pooled capacity (that used to meet their own forward showing
metrics) to the pool; which resources are dispatched to meet their
own or the regions needs would remain in their control.
PNUCC General Remarks
- Overall the Conceptual Design document is very
well-done and helpful.
- Thank you for this comment.
LOLE
- Is the increment/metric determined or yet to be
decided for the NWPP Region? If not specified yet, it
would be helpful to document a couple of elements
that are being considered in establishing the
appropriate metric and/or the reasons it is a
challenge to pick one. And if it is well defined.
- The SC recommends a loss of load expectation (LOLE) objective of 1
day in 10 years where capacity is expected to be insufficient to meet
load plus contingency reserves. An event is defined as a time when
all reserves (e.g., RA reserves) have been exhausted except those
that are set aside as contingency reserves. An event could be
multiple hours in a day; loss of load hours in a single day, whether
consecutive or non-consecutive, would constitute a single event. The
reliability metric will be revisited at the end of Phase 2B.
Coincident versus Noncoincident Peak Load
- Coincident vs. non-confident peak load. If I recall,
there was still a question about that, but I’m not
sure why.
- At this point there is general consensus among the SC member that
the obligations will be allocated based on non-coincident peak
loads, but this issue will be re-examined as program design is
completed, as we appreciate that many of these design decisions are
interrelated.
Hydro Methodology
- The thought is that summer flows are pretty tight,
regardless of the assumption the hydro availability
won’t swing much. However, in winter with such a
- The hydro methodology will be based on an analysis of the
capability of the storage hydro facilities during capacity critical
hours, the hours within a day where the delta between forecasted
net load and generation is the smallest, over a 10-year period, and
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Stakeholder Comments Steering Committee (SC) Response
spread in possible flows, will there be a risk of being
too optimistic if water conditions are really poor. A
few sentences to elaborate on the average water
thinking could help.
as such will reflect the capability of hydro in a range of water
conditions (and the associated storage conditions) in both the
summer and winter seasons. Further, we will consider storage hydro
critical hour capabilities in specific low water years to evaluate the
impact of low water on the storage hydro fleet’s capacity
contribution during capacity critical hours. Hydro capacity
contribution will be addressed in a SAC technical workshop.
Renewable
Northwest and
NW Energy
Coalition
RA Program Goals and Objectives
- Suggest the addition of “resource diversity and
transparency across the program” as objectives with
respect to information sharing for the purpose of
achieving an efficient and fair common pool sharing
among RA entities.
- Objectives of the RA Program should capture the
full range of adequacy risks on an annual,
seasonal/monthly and super-peak basis, and should
strive to avoid bias toward any specific type of
resource.
- We suggest adding an emphasis that the program
should optimize net benefits to the entire region
and assure beneficial results to all Participants.
- Recommend engagement with developers and
subject matter experts to understand technical and
operational characteristics of emerging
technologies.
- Thank you for your comments. The SC agrees that a regional RA
Program should be technologically neutral and should be designed
to not exclude any resource types that members may choose to
meet their requirements, but rather to appropriately accredit
capacity based on the operating characteristics of the resource.
- The program design is intended to optimize the benefits to all
participating entities and take advantage of the diversity in loads
and resources across the footprint of the program. An inherent
benefit of regional RA is lower overall cost to achieve the same level
of reliability that would be possible under individual utility planning
for RA. The realization of investment savings is one of the program
objectives identified by the SC. The benefits of increased reliability
and lower costs and risks will benefit the region as a whole.
- The SC will consider the recommendation to engage with
developers and subject matter experts to understand the technical
and operational characteristics of emerging technologies.
Governance and Regulatory Impacts
- We recommend developing a more structured
stakeholder participation and input process so that
the design decisions and program operation can be
made more consistent and forward looking.
- We recommend strong coordination with state and
provincial regulatory bodies to align the RA
- The SC agrees that stakeholder input is essential to the RA Program
development and future stakeholder engagement may evolve into a
more formal process as we get closer to implementation and after
the PA is hired.
- The SC has begun to conduct state outreach intends to continue
such outreach throughout program development.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Stakeholder Comments Steering Committee (SC) Response
Program with their existing processes relating to
resource adequacy.
Forward Showing Program Conceptual Design
- How will obligation at the LSE level impact who may
offer resources into the program? For non-load
serving entities with resources capable of providing
capacity, how will the program work to allow
participation?
- Suggest an annual update of seasonal PRM based
on changes in load and shift in peak demand hours.
This would be essential for RA entities to inform
short-term capacity planning as more renewable
and storage resources come online.
- Suggest a study of non-coincident peak and multi-
day capacity critical hours which may affect
individual BAA’s system reliability.
- Suggest a transparent process for data sharing and
dispute resolution on PA’s load forecasting
methodology and results. This would ensure that
potential resources are well-equipped to provide
firm capacity into the sharing program.
- Independent generators who have contracted their supply would be
treated like utility-owned resources. The SC will further clarify how
independent generators fit into the program in Phase 2B.
- The SC will consider these suggestions while developing detailed
program design Phase 2B.
- The SC appreciates your considerations related to the proposed load
forecasting approach. Load forecasting methodology will be a topic
for further discussion in Phase 2B. The SC recognizes the importance
of accurate load forecasts and firm resource commitments in order
to determine adequacy and ensure reliability.
Showing and Compliance Timeline
- Relying solely on seasonal showing requirements
tends to discount the value of resources and the
intra- seasonal variability in demand and supply in
the region.
- The SC should consider more frequent showing
periods during each compliance season based on
rigorous modeling to optimize economic
performance, fairness, and reliability. As a starting
point we suggest publishing monthly capacity-
- The SC will consider these suggestions while developing detailed
program design in Phase 2B.
- The SC agrees that formulation of capacity critical hours is an
important design element. During the Phase 2A discussion, the SC
determined that showings requirements timelines need to ensure: 1)
that the requirements that each entity has to meet for each
upcoming binding season can be known with certainty to facilitate
resource acquisition contracting timelines and outage planning for
the member entities, and 2) that the PA can do a timely evaluation
of the footprint in advance of the binding season such that any
issues can be identified and addressed well in advance. The
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Stakeholder Comments Steering Committee (SC) Response
critical hours and considering the possibility of
quarterly or monthly showing periods.
- We recommend a detailed assessment and an
evolutionary process to inform the formulation of
the capacity-critical hours in the region. These issues
are being examined elsewhere, such as the current
review of availability assessment hours for the
CAISO RA Availability Incentive Mechanism (RAAIM).
- We recommend providing a flexible updating
process for hydro resources, to avoid the risk of
deficiency during the showing period due to
changing weather and stream conditions.
- An additional factor that must be addressed for all
Columbia River hydro resources is the changes in
the operation of the Columbia River Treaty starting
in 2024.
proposed showings periods were considered to be of the right
granularity for modelling purposes, while facilitating those two
objectives.
- The SC is developing a methodology for capacity qualification of
hydro resources. The hydro methodology will be based on an
analysis of the capability of the storage hydro facilities during
capacity critical hours, the hours within a day where the delta
between forecasted net load and generation is the smallest, over a
10-year period, and as such will reflect the capability of hydro in a
range of water conditions (and the associated storage conditions) in
both the summer and winter seasons. Further, we will consider
storage hydro critical hour capabilities in specific low water years to
evaluate the impact of low water on the storage hydro fleet’s
capacity contribution during capacity critical hours. This topic will be
further discussed with the advisory committee in Phase 2B.
Planning Reserve Margin
- A more granular and probabilistic approach is
needed to evaluate intra-seasonal stress conditions
and super-peak periods within seasons which will
likely become more prominent with the effects of
climate change and increasing electrification of
loads.
- It will be important to consider calculating more
granular monthly LOLE or LOLP values initially to
highlight the high-stress periods and allow
resources the opportunity to supply that need.
- We recommend a technical workshop to study more
granular approaches. The Northwest Power and
Conservation Council’s ARM1 and ASCC metrics can
- The SC will consider these suggestions while developing detailed
program design in Phase 2B.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Stakeholder Comments Steering Committee (SC) Response
be considered to assess the interactive effects of a
diverse resource portfolio.
Load Forecasting for Forward Showing
- The Conceptual Design document mentions that
“the PA will model either the coincident or non-
coincident peak demand for the region”. This aspect
of the program is critical to set regional metrics and
would need to be addressed in Phase 2B.
- Load forecasts should be consistent with integrated
resource planning methods, including regional
planning such as Northwest Power and
Conservation Council’s Needs Assessment, and
provide an integrated program forecast rather than
rolling up the forecasts of participating entities.
- At this point there is general consensus among the SC member that
the obligations will be allocated based on non-coincident peak
loads, but this issue will be re-examined as program design is
completed, as we appreciate that many of these design decisions are
interrelated.
- Thank you for this comment. The SC intends to address RA
contracting practices as well as the topic of RA Program interaction
with current and planned regional market initiatives in a technical
workshop.
Regional Import/Export Assumptions
- An exploration of potential unintended
consequences on the utility procurement process to
limit competition, increase contract costs, or shift
risk to IPPs and consumers should be considered in
the planning phase of the program.
- Suggest more deliberate analysis on how this
program will operate within the construct of a
regional day ahead market and also the possibility
that the program could at some time operate within
a larger wholesale electricity market across the
region.
- Thank you for this comment. The SC intends to address RA
contracting practices as well as the topic of RA Program interaction
with current and planned regional market initiatives in a technical
workshop.
- Further technical discussions with the SC and the PD will determine
the day ahead and real-time planning requirements and outline the
role of the PA in this time horizon. This would include how
Participants will be assessed as being compliant during the
operational timeframe, which may involve metrics that take into
account actual operational conditions. Within the day ahead and
real-time windows, member entities also participate in various
existing wholesale bilateral and organized markets (e.g., EIM). In
Phase 2B, the SC and PD will further consider how the operational
program design will integrate with these markets, including the
potential overlay between RA and RS metrics in the day ahead
timeframe.
Resource Eligibility and Qualification - The SC has elected to use a pure capacity methodology to assess
capacity contributions and agrees that it is imperative that capacity
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Stakeholder Comments Steering Committee (SC) Response
- It is our understanding that planned outages will not
be included in UCAP calculations. It will be critically
important that resources present their scheduled
outages in the RA workbook to adequately
represent the full availability of the resource during
capacity critical hours.
- Consistent and accurate calculation of UCAP needs
significant attention. Currently, for example, the
CAISO is considering an approach that would
quantify Forced Outage, Urgent Outage, Planned
Outage and Opportunity Outage, but only
Forced/Urgent Outage would count as UCAP. These
factors should be considered in the NWPP RA
Program.
- A sound methodology needs to be formulated for
assessing capacity contributions of emerging
technologies like standalone storage, hybrid, and
demand response resources, which will play a
pivotal role in future buildouts in the region. Due to
lack of operational data for these technologies,
initial capacity accreditation method should be
reasonably selected, and then revisited by a formal
method informed by data collection on
operationality and deliverability. The timeline for a
formal method could be set after 2 years of
operational data collection.
represented in workbooks is accurate and reflective of planned
outages. Capacity contributions for individual resources will be
evaluated using the identified methodology (thermals using UCAP,
for instance). When participating entities claim a resource in the
forward showing program, they will be responsible for identifying
planned outages and supplying replacement capacity for those
times units would be offline.
- The SC will further consider outage procedures (for outages planned
both before and after the showing deadline, forced outages, etc.)
during Phase 2B. It is anticipated that forced outages rates would be
accounted for in UCAP calculations, though more detailed
consideration of forced outage treatment (as suggested) will be
undertaken in Phase 2B.
- The SC is committed to ensuring technology neutrality of the
program (accurately assessing all resources’ contribution to regional
reliability during capacity critical hours) and to enabling contribution
by all available resources able to meet program requirements. The
SC will consider these suggestions while developing detailed
program design in Phase 2B, including the need to evaluate capacity
contributions of new resources (lacking in historical data).
Capacity Contribution of Resources
- The Northwest Power and Conservation Council has
developed methods to assess the complementary
effects of coordinated hydro with other resources,
thus valuing all resources not merely for their hours
of output capability but also their interaction with
other resources on the system. Methodologies such
- Thank you for these suggestions; the SC will consider these while
developing detailed program design in Phase 2B. We have
addressed as many of the suggestions as we currently are able but
have noted the others for further consideration.
- Capacity contribution of demand response and hybrid resources
(e.g., solar and batteries) will be further discussed in Phase 2B; the
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Stakeholder Comments Steering Committee (SC) Response
as the ARM and ASCC model this dynamic. This
approach should be considered in the NWPP RA
Program.
- The assessment of demand response should be
based on probabilistic models of availability. Phase
2B and the preceding should continuously
incorporate new research and best practices for
more dynamic modeling of demand response.
- Recommend that the penalty amounts for deficiency
should be commensurate with resource type. It may
not be accurate to apply a CONE methodology
using a natural gas fired peaking facility when
assessing penalties on solar, wind, or hybrid
generators which do not incur the same capital and
operating costs.
Wind and Solar
- We recommend a 5-year historical generation
forecast instead of a 3 year to inform QC values for
wind and solar resources.
- Last-in ELCC framework should be considered for
informing resource contributions of renewable
resources instead of using deterministic methods.
This methodology is explained in E3’s work3
presented before Oregon PUC in UM 2011 docket
on General Capacity Investigation.
- More clarity on how wind and solar resource zones
are selected would be helpful. The resource zones
should be selected based on resource availability
and not be constrained by available transmission.
- Recommend studying the interaction among solar,
batteries, pumped storage, and DR/EE resources,
along with dynamic peak assessment and how they
SC appreciates the need to enable these emerging technologies to
contribute to a regional RA Program.
- The SC’s use of the CONE factor as a penalty is intended to strongly
motivate Participants to comply with program metrics in the forward
showing time horizon. This penalty would not be associated with any
particular resource (e.g., solar, wind, etc.), but would be levied
against an entity which did not show adequate resources in the
forward showing portfolio. In the forward showing program, entities
choose what resources to use to meet the adequacy objective. The
compliance penalty is associated with the cost of a natural gas fired
peaking facility as a proxy to illustrate a way the program could
close a gap left by a non-compliant entity; the use of this particular
resource type is hypothetical, used to arrive at a basis for assessing
the penalty.
- The SC is considering appropriate length of historical data requests,
balancing the value of additional data against data availability; this
will be a topic for further discussion in Phase 2B.
- Zones for ELCC studies are not anticipated to be transmission
related, but instead based on geographical/fuel-related similarities.
This recommendation will be re-assessed as program design is
considered in greater detail; the SC recognizes that all program
design elements will be interrelated and should be evaluated for
consistency in approach.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Stakeholder Comments Steering Committee (SC) Response
can improve the carrying capacity of each resource
depending on load profiles and the
diversity/distribution of the underlying resources.
Storage
- Pumped hydro storage resources and battery
storage resources are essential to long-term
reliability, flexibility and grid integration of
renewables.
- A reasonable option would be to use Pmax as the
QC for storage resources which are not under ITC
charge restrictions initially and then transition to an
ELCC method eventually. Last-in ELCC method could
also be used, similar to the approach for solar and
wind resources.
- Hybrid Resources
- Since historical data for hybrid resources are not
abundant, initially, we recommend a new
methodology to calculate the Net Qualifying
Capacity (NQC), suggested by SCE and adopted by
CPUC5. This methodology accounts for the portion
of output from the renewable resource necessary to
fully charge the battery and the expected remaining
capacity available to the grid for RA, and adds to
that the QC value of the battery based upon the
amount it can be expected to charge from the
renewable device.
Transmission and Deliverability
- The establishment of transmission and resource
zones must be carefully considered so as not to
aggravate challenges with deliverability.
- We suggest a technical group focused on evaluating
the potential impacts to transmission rates and
- Thank you for this comment. The SC will further evaluate
transmission deliverability in a technical workshop and will consider
these recommendations/comments provided.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Stakeholder Comments Steering Committee (SC) Response
contracting provisions as a result of establishment
of zones within and across existing balancing areas.
- We suggest that within this technical discussion, the
SC evaluates other potential secondary impacts of
the RA Program on meeting clean energy mandates.
Our concerns include the following:
- A preference for utility owned resources to meet RA
needs due to transmission requirements.
- A challenge for new resources to count towards RA
given the lack of clarity on how capacity
contributions during capacity critical hours will be
evaluated for new resources.
Operational Program Design and Linkages with Other
Regional Initiatives
- During the operational phase of the program, the
PA should play a key role to independently
determine the day ahead and real-time planning
requirements.
- We recommend further discussion on interaction of
the NWPP RA Program elements like deliverability
with regard to existing bilateral transactions, the EIM
and future Extended Day- Ahead Market (EDAM)
initiative.
- Recommend the SC to identify touchpoints with
EDAM in future as the NWPP RA Program design
gets clearer.
- An ongoing stakeholder group should be
established to review operational reports and
performance metrics and provide input to program
refinement.
- Thank you for this comment. The SC intends to address the topic of
RA Program interaction with current and planned regional market
initiatives in a technical workshop.
- Further technical discussions with the SC and the PD will determine
the day ahead and real-time planning requirements and outline the
role of the PA in this time horizon. This would include how
Participants will be assessed as being compliant during the
operational timeframe, which may involve metrics that take into
account actual operational conditions. Within the day ahead and
real-time windows, member entities also participate in various
existing wholesale bilateral and organized markets (e.g., EIM). In
Phase 2B, the SC and PD will further consider how the operational
program design will integrate with these markets, including the
potential overlay between RA and RS metrics in the day ahead
timeframe.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Stakeholder Comments Steering Committee (SC) Response
- Phase 2B should survey and understand regional
distribution system planning, non-wires alternatives
and other transmission/distribution interface
proceedings and efforts as they relate to local RA
conditions and remedies.
Legal and Regulatory Requirements
- It is still important to create an independent board
before the binding program is developed.
- How will the program report out to each
participating state regulatory body? Recommend
regular updates and reporting.
- The SC appreciates the interest and importance of governance of
the program to stakeholders and intends to discuss this further in a
technical workshop.
PNGC Governance/Point of Compliance
- What entity is required to meet the obligation is one
of our primary concerns. Should the compliance
obligation reside with an LSE like PNGC and other
BPA customers serving retail load, or Balancing
Authority’s (BA) like BPA/PGE/PAC?
- The SC appreciates the interest and importance of governance of
the program to stakeholders and intends to discuss this further in a
technical workshop.
System Requirements
- What technology platform/software is needed?
- Who pays those costs?
- How will the RA Program costs be collected and
allocated?
- Could this decision change program compliance as
expressed in the Conceptual Design document?
- The technology platform and software have not been determined at
this time. The SC will work with the PD in Phase 2B to identify any
technology needs for final implementation.
- Allocation and collection of costs have also not been determined at
this time. Cost and the allocation/collection of the full RA Program
will be developed towards the end of Phase 2B.
- The SC recognizes that many of these design elements are
interconnected and may impact one another; we are committed to
evaluating the design when it is complete to ensure elements align;
in this way, compliance considerations could be impacted by
decisions regarding program costs and allocation methodologies,
though at this point the SC has not specifically identified this as an
issue.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Stakeholder Comments Steering Committee (SC) Response
Access to Pooled Regional Resources
- How will this sharing ultimately work, what will the
process be to tap into these?
- Can non-NWPP entities access the benefits of RA
and the pool sharing mechanism?
- Work is being done currently in Phase 2B with the help of the PD on
the final design for sharing benefits of a fully implemented RA
Program in the operational time horizon. More specific processes,
procedures, calculations, etc. will be considered as the detailed
design of the operational program is refined. Generally, the intent is
to allow an LSE access to pooled capacity if their load (+ extenuating
circumstances like net VER production) is higher than was planned
for in the forward showing. They may have the option to use the
market to meet their needs rather than accessing the pooled
capacity, though the logistics of access will be considered further in
Phase 2B.
- The pooled capacity would only be accessible to NWPP RA
Participants, as it would be essential that those accessing the pooled
capacity had participated in the forward showing program to
demonstrate that they have acquired resources to contribute fairly
to the pooled capacity in the operational time horizon.
Capacity Versus Energy
- Agree with approach to start with a capacity
program.
- Once a regulated entity meets the showing period
with capacity the requirement is satisfied. No
shorter-term energy requirement is applicable past
2 month true up from the capacity forward showing.
- System triggering events
- What lead time is provided here? How will the alert
be provided?
- How will this impact bilateral trading markets like
Daily, Weekly, or BOM deals?
- How does a regulated entity demonstrate a sale is
surplus to seller’s needs?
- Correct – no shorter-term (beyond a few hours) energy requirement
is being developed by the SC at this time. If an entity meets their
capacity showing requirements at the end of the cure period, they
will not be required to contract for additional resources after that
deadline (barring unforeseen maintenance outage needs, etc.).
Entities will be responsible for holding the capacity they claimed in
the forward showing until it is either called upon for an event or
released by the PA when forecasts indicate that an event is highly
unlikely to occur.
- The SC is focused on implementation of a capacity RA Program.
Once a capacity RA Program is implemented, the SC could build on
the program by addressing an energy or flexibility RA Program.
- Final design details on lead time and any such impacts on bilateral
trading markets are currently being discussed in Phase 2B with the
help of the PD. This includes how an entity would demonstrate
surplus RA capacity for possible sale in the marketplace.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Stakeholder Comments Steering Committee (SC) Response
- The SC also intends to address RA contracting practices/paradigm in
a technical workshop with the SAC.
Capacity Factor Calculation
- Ensure hydro and other resources have similar
accreditation calculations.
- More insight into storage hydro projects, including
pump hydro, needed.
- Although final details on the qualifying capacity contribution for
resources are still being determined in Phase 2B, the SC recognizes
the unique situation that the Northwest is in with its prevalence of
storage hydro resources. Because of this, special consideration will
be given to the capacity calculation for storage hydro. The hydro
methodology will be based on an analysis of the capability of the
storage hydro facilities during capacity critical hours, the hours
within a day where the delta between forecasted net load and
generation is the smallest, over a 10-year period, and as such will
reflect the capability of hydro in a range of water conditions (and
the associated storage conditions) in both the summer and winter
seasons. Further, we will consider storage hydro critical hour
capabilities in specific low water years to evaluate the impact of low
water on the storage hydro fleet’s capacity contribution during
capacity critical hours.
Unplanned Outages
- With how planned outages are discussed we feel
keeping just two seasonal periods is optimal.
Because it provides certain timeframes to allow for
planned maintenance of units outside of showing
periods.
- While the SC has identified four seasonal periods, two of these
seasons are identified as “advisory.” During the Fall and Spring
seasons, the PA would supply adequacy objectives, but participating
entities would not be penalized for not meeting these metrics; this
would allow Participants to plan maintenance during these
“advisory” shoulder seasons.
Transmission Procurement Obligation
- Could a resource be downgraded in capacity value
due to lack of firm or conditional firm transmission?
- How would secondary network transmission (6-nn)
be valued compared to Conditional Firm?

- The SC recognizes the importance that firm transmission plays in
both the contribution of capacity in a forward showing period and
the ability to deliver RA benefits in the operational period.
- Final details on capacity contribution for resources are still being
developed in Phase 2B with the help of the PD and Regional
Transmission Organizations.
- The SC intends to address transmission deliverability and RA
contracting practices in a technical workshop and will consider the
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Stakeholder Comments Steering Committee (SC) Response
recommendations for specific details the workshops should cover as
we develop the meeting agendas.
Washington
UTC
General Remarks
- The production of the Conceptual Design working
document represents a major first step in
developing a Resource Adequacy (RA) program that
has the potential to help the region meet its
capacity needs as it transitions off of carbon based
fuels and to support more efficient commercial
trading and economic use of capacity. It
demonstrates the progress the Northwest Power
Pool members have made and reveals many of the
complex challenges facing the Resource Adequacy
Program Development Project (RAPDP).
- In addition to considering specific elements of the
RA Program design, it is important to keep in sight
the broad requirements any Northwest (NW) RA
Program must fulfill. A NW RA Program must
calculate capacity needs during critical water years
and temperatures. It must encompass the full range
of historic variations and patterns of the natural
stream flow available to the hydroelectric
generation systems for generating energy and
capacity and the energy available to variable energy
resources (VER). The variations in temperature and
water years must also be adjusted for the effects of
greenhouse gas (GHG) driven climate warming. The
SC should include these goals in the phased work
schedule of the RAPDP.
- Thank you for your comments.
Capacity RA Program
- Designing a capacity RA-based program is a
practical and achievable first step. A successful RA
Program must consider the interrelationship
- The SC identified capacity RA as the most urgent need facing the
region. Further, though its implementation presents a number of
challenges, a capacity adequacy program is the most straightforward
to implement.
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Stakeholder Comments Steering Committee (SC) Response
between capacity and energy, as well as generation
ramping capacity (flexibility). The phased work
schedule should include target dates for including
energy constraints and flexibility capacity.
- The capacity RA Program will address the needs of the region in the
capacity critical hours which are the hours within a day where the
delta between forecasted net load and generation is the smallest.
Once the capacity program is implemented, the SC will explore
whether there are other solutions that could build upon this
program, such as an energy adequacy standard. Further, the SC
recognizes that there can be challenges associated with prolonged
low water conditions in the region, and in Phase 2B will work
together to evaluate the impact a low water scenario might have on
the hydro storage capacity capability during critical hours to
determine if changes to the RA requirements should be made. This
topic will be further addressed a SAC technical workshop.
Greenhouse Gas-Driven Climate Change
- The Conceptual Design does not speak directly to
GHG climate change. If the effects of climate change
are to be incorporated into a region-wide RA
Program, it will need to be applied in a consistent
manner to all loads and resources.
- The SC agrees that the impacts of a changing climate on loads and
resources is an important topic and should be considered in long-
term resource planning. The RA Program is being designed for a one
year out forward program time horizon. The historical data used in
the calculations of certain design elements will be determined
during Phase 2B. Further, the SC has identified technology neutrality
as a key objective for the RAPDP effort. As states will retain control
over resource procurement decisions, the RA Program would supply
additional information related to resources’ contribution toward a
reliable grid. In this way, the program will enable states and
participating LSEs to meet greenhouse gas (GHG)- and climate-
related portfolio standards while maintaining regional reliability.
Resource Capacity Accreditation
- The methodologies for accreditation are reasonable.
However, maintaining resource neutrality includes
developing capacity ratings for similar resources in a
similar timeframe. Keeping with this principle,
battery storage and demand response should be
included with the development of an accreditation
methodology for Storage Hydro during Phase 2B.
- Thank you for your recommendation. The RA Program is intended to
be technology agnostic and the SC acknowledges that evaluation of
qualifying capacity contribution in similar timeframes helps signal
resource neutrality.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Stakeholder Comments Steering Committee (SC) Response
Planning Reserve Margin
- The derivation of the Planning Reserve Margin
(PRM) may need further discussion as the RA
Program develops. For the RA Program to be
effective for all load and resource conditions, the
PRM must be calculated using the variation
reflected in all of the available historic data with
adjustments for the effects of GHG driven climate
warming.
- Thank you for your recommendation. The PRM continues to be
discussed during Phase 2B.
Import Capacity
- The import capacity requirements in the Conceptual
Design are appropriate and necessary. The SC
should consider applying those same requirements
to the deliverability of resources to local zones
inside the footprint of the RA Program.
- Thank you for your recommendation. The SC is considering
deliverability of resources related to forward showing and
operational time horizons, as well as contract eligibility requirements
as part of the Phase 2B scope. Ensuring that transmission availability
is considered in the design of both forward showing regional and
entity-specific metrics, and in design of operational program
logistics will be a priority for the SC in coming months.
Qualifying Capacity Contribution Methodology
- The SC should consider using five years of historic
data for thermal resources. Additionally, the SC
should examine the benefits of using all available
production data for calculating the Effective Load
Carrying Capacity (ELCC) for VERs. For instance, it
should examine if revisiting the ELCC of a VER as
additional historic data is available might increase
the accuracy of the ELCC for that resource. For a VER
with only 3-6 years of historical production data, the
SC should examine if using zonal class information
in conjunction with the 3-6 years data might
improve the accuracy of the ELCC.
- Thank you for your recommendation. The SC will further consider
appropriate timeframes for informing ELCC studies and capacity
contributions of all resources in Phase 2B. Availability of data for
recent resource additions will be considered, as will the need to
balance the desire for as much data as may be available with the
burden of collecting/processing additional data and the desire to
create consistent and repeatable study parameters. Specifics
regarding these studies will be discussed further in Phase 2B.
Transmission and Deliverability
- Much of the diversity in load and resources that
could be available to NW entities through a RA
Program is located beyond the interties connecting
- Thank you for this comment. The SC will further evaluate
transmission deliverability in a technical workshop and will consider
these recommendations/comments provided.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Stakeholder Comments Steering Committee (SC) Response
the NW to other portions of the Western
Interconnect. The RA Program will need to directly
answer what capacity the interties can deliver to the
NW.
- The RA Program should include zonal modeling on
an ongoing basis and require the PA to designate
RA requirements for local zones. It should examine
internal flow gates and designate RA requirements
for local zones as necessary. Finally, the RA Program
should also work with its members to determine the
need for resources to provide voltage support,
inertia, and frequency response.
- Also, we are coordinating with all of the BAs participating in the
program (including all of the critical transmission providers) and with
the Northern Grid transmission group. We will use the input from
these groups in addition to the SC members with transmission to
consider transmission constraints etc.

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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NWPP Resource Adequacy
Program Detailed Design

Glossary

JUNE 2021

Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Glossary
Advisory Season – Annual periods for which program compliance is not mandatory
(deficiency payments will not be applied for non-compliance with FS metrics). Spring (March
16 – May 31) and Fall (September 16 – October 31) seasons will be advisory and non-binding.
Annual Assessments – Studies and analyses performed by the Program Operator on an
annual basis that includes the Loss of Load Expectation (LOLE) study that makes a
determination of a planning reserve margin (PRM) for Program Participants, Effective Load-
Carrying Capability (ELCC) studies that make a determination the of qualified capacity
contribution (QCC) of Variable Energy Resources (VERs), and additional QCC studies for all
other resource types.
Behind-the-meter generation – Generally, generating resources owned by customers or
other third parties that are located beyond the utility metering point.
Binding season – Annual periods for which program compliance is mandatory (penalties will
be applied for non-compliance with FS metrics or Operational Program requirements).
Summer (June 1 – September 15) and Winter (November 1 – March 15) seasons will be
binding.
Capacity Critical Hour (CCH) – Hours where the net regional capacity need is above the 95th
percentile (highest capacity need hours).
Capacity Resource – A resource that has been assessed a QCC value and can count toward a
Participant’s FS capacity requirement.
Capability testing – Tests that verify generator real and reactive power capability that meet,
at a minimum, the requirements of NERC standard MOD-025.
Centroid – A central location on the electric grid utilized to transact power to and from in
order to provide for a known location to enact RA Program deliveries.
Committee of States (COS) – the group of state or provincial regulators established
pursuant to the NWPP bylaws, consisting of one representative from each state of the
Participants participating in the RA Program.
Contingency Reserves – The provision of capacity that may be deployed by the Balancing
Authority to respond to a Balancing Contingency Event and other contingency requirements
(such as Energy Emergency Alerts as specified in the associated Emergency Operating Plan
standard).
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Cure period – Timeframe for Participants that have had deficiencies identified in the Forward
Showing data submittal are allowed to supplement their submittals to meet Program
requirements.
Customer resources – see behind-the-meter generation.
Delivery Failure Penalties – Monetary charges to a Resource Adequacy (RA) Participant who
fails to deliver during Energy Deployment.
Δ Forced Outages - includes any unplanned reliability outages or unplanned reliability de-
rates associated with thermal generation units, storage hydro units and transmission outages
impacting firm capacity for the operating day. Does not include economic outages and de-
rates.
Δ Run-of-River Performance - comparison of forecasted run-of-river production vs.
Qualified Capacity Contribution (QCC) of run-of-river hydro. Includes both over and under
performance.
Δ Variable Energy Resource (VER) Performance - comparison of forecasted VER production
vs. QCC of VER. Includes both over and under performance of wind and solar plants.
Demand response program – Generally, a program that allows end use customers to reduce
their electricity usage during periods of high energy prices.
Energy Deployment – An hourly MW value (MWh) that a RA Participant is assigned to deliver
during a Sharing Event in order to assist another deficient Participant.
Energy Deployment Calculation – the Sharing Calculation, when performed at T-120 to
identify how much energy should be deployed.
Energy Storage Resource (ESR) – A resource capable of receiving energy from the electric
grid (either directly or through energy conversion) and storing it for later injection of electric
energy back into the grid.
Extended Day-Ahead Market (EDAM) – The California Independent System Operator’s
proposed initiative that extends participation in the day-ahead market to the Western Energy
Imbalance Market (EIM) entities.
Firm block – Energy that is interruptible only for reasons of Uncontrollable Force or to meet
the Seller’s public utility or statutory obligations to its customers, provided those obligations
are for reliability of service to native load.
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Forced outages – Includes any outages or de-rates associated with thermal generation units,
storage hydro units and transmission outages impacting firm capacity import that are not
planned.
Forced outage rates (EFOR) – Metrics taken from the NERC Generator Availability Data
System (GADS) that are used for analyses including the LOLE and QCC studies
Forward showing (FS) capacity requirement – An entity’s P50 load plus a planning reserve
margin (P50+PRM); the amount of qualified capacity (in MW of QCC value of resources,
contracts and/or RA transfers) an entity must demonstrate rights to at the FS deadline.
FS deadline – Date at which FS portfolios are due to the Program Operator for compliance
review (7 months in advance of the start of each binding season).
FS portfolio – The set of data submitted by a Participant to show they have met their FS
capacity requirement. This workbook will include all resources owned by the Participant, RA
capacity contracts, and RA transfers.
FS Program – Portion of the RA Program that deals with forward looking planning aspects of
the Program. The FS Program includes the performance of Annual Assessments and the
administration of FS submittals.
FS Submittals – Data submittals provided by Program Participants to the PO twice a year
(March 31st and October 31st) to demonstrate compliance of FS Program requirements.
Grandfathered agreement – Contractual agreements with effective dates prior to the start of
the RA Program.
Holdback Requirement – The hourly MW value that a RA Participant is asked to reserve as
capacity for use by the Program during a forecasted Sharing Event. For Participants with a
positive Sharing Requirement, that Sharing Requirement will be allocated pro rata by positive
Sharing requirement to equal the total of the negative Sharing Requirement MWs from
deficient Participants. Holdback Requirement is capped at the Sharing Requirement value.
Hybrid resources – For purposes of the RA Program, resources that contain both an Energy
Storage Resource and a second resource type (VER or thermal or other)
Independence – Financial independence from individual RA Program Participants and classes
of Participants in order to ensure that any such interests do not contribute to undue
discrimination by the NWPP.
Installed Capacity (ICAP) – A MW value based on the seasonal net dependable capacity of a
unit. Forced outage rates are not accounted for in an ICAP value.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Load Forecast - Forecasted load for the Operating Day (OD) considering the forecasted
weather conditions of the OD.
Load forecast uncertainty (LFU) – In the determination of PRM, the probability of the loads
that are experienced will be either higher or lower than forecast.
Load Responsible Entity (LRE) – An LRE is an entity that (i) owns, controls, and/or purchases
capacity resources, or is a Federal Power Marketing Agency, and (ii) has the obligation, either
through statute, rule, contract, or otherwise, to meet energy or system loads at all hours.
Subject to the aforementioned criteria, an LRE may be a load serving entity (“LSE”) or either
an agent or otherwise designated as responsible for an LSE or multiple LSEs or load service
under the RA Program.
Multi-Day Ahead Assessment – A non-binding, forecasting run conducted by the Program
Administrator (PO) over the upcoming operational horizon utilized for predicting and
communicating possible upcoming Sharing Events. This information is provided to
Participants for situational awareness and is non-binding.
Net Contract QCC – Summation of the QCC of a Participant’s purchases and sales used in the
RA Program
Net Peak Demand – The forecasted Peak Demand less the projected impacts of Demand
Response Programs
Nominating Committee (NC) – The committee established by the NWPP bylaws to identify a
nominee or nominees for positions on the BOD.
NWPP Storage Hydro QCC Methodology – Customized methodology for determining the
QCC of storage hydro projects in the NWPP RA FS Program. The methodology considers each
resource’s actual output, water in storage, reservoir levels, and project flow constraints. The
methodology is fully detailed in Appendix D.
Operating Day (OD) – The day of operations.
Operational (Ops) Program – The Ops Program creates a framework to provide Participants
with pre-arranged access to capacity resources in the Program footprint during times when a
Participant is experiencing an extreme event.
Operational timeframe – the timeframe that begins at the first holdback assessment and
ends at real-time.
P50 – Participant load forecast that has a 50% probability of not being exceeded during the
season for which it is applicable.
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Participant – Entities participating in the NWPP RA Program (i.e., an LRE that signs the
Western Resource Adequacy Agreement (WRAA).
Peak Demand – The highest demand including a) transmission losses for energy, b) the
projected impacts of Non-Controllable and Non-Dispatchable Behind-the-Meter Generation,
and c) the projected impacts of Non-Controllable and Non-Dispatchable Demand Response
Programs measured over a one clock hour period.
Planned outages - Outages or de-rates associated with thermal generation units, storage
hydro units and transmission outages impacting firm capacity import that are not mandated
for the purposes of reliability, safety of equipment or personnel and are at the discretion of
the owner.
Planning Reserve Margin (PRM) – A percentage of dependable capacity needed above the
P50 Load Forecast to meet unforeseen increases in demand and other unexpected conditions.
Point of Compliance - The Load Responsible Entity which has a compliance obligation to the
RA Program.
Portfolio QCC – Summation of a Participant’s QCC from its owned or contracted Resources,
its purchase and sales agreements, and its RA transfer purchase/obligations
Program Operator (PO) – The entity providing the knowledge, expertise, staff, systems, and
technology to implement the Forward Showing and Operational Programs.
Public Utility – for the purposes of this document, public utility should be understood per
the Federal Power Act and FERC jurisdictional implications.
Pumped storage facilities – Hydro facilities that have a storage reservoir located on the
upstream side of the facility that may be filled by pumping water from the downstream side.
Pure capacity – Term used in technical analyses that represents a constant generating source
that has no outage rate
Qualified Capacity Contribution (QCC) – The number of megawatts eligible to be counted
towards meeting a Participant’s FA capacity requirements.
RA Program footprint – The physically and contractually interconnected power system
represented by the generating resources, transmission systems, and load serving facilities of
Program Participants.
RA Transfer Agreement – A type of capacity contract where the seller assumes part of the
purchaser’s FS capacity requirement (RA obligation) – see Section 2.4.2.2 for additional detail
on these contracts. Under specific circumstances in the Ops Program, energy from these
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contracts will be deployed to serve either the needs of the purchaser or of the program (see
Section 3.4.4).
Regulator Committee (RC) – The group of state or provincial regulators established
pursuant to the NWPP bylaws, consisting of one representative from each state for the area
including all Participants participating in the RA Program.
Release of Capacity – when a Participant is no longer expected to hold (or use to meet load)
the amount of capacity from the FS capacity requirement and can use that capacity as
desired.
Resource – Typically, a device capable of providing electric energy to the transmission grid.
Resource Adequacy (RA) – NERC defines it as “the ability of the electric system to supply the
aggregate electric power and energy requirements of the electricity consumers at all times,
taking into account scheduled and reasonably expected unscheduled outages of system
components. In order to ensure supply always matches demand, electric system operators
and planners rely on reserves. There are two principal types of reserves, shorter-term
operating reserves and long-term planning reserves.”
Resource Adequacy Participant Committee (RAPC) – This committee is comprised of
Participants and is responsible for developing and recommending policies, procedures, and
system enhancements related to the policies and administration of the RA Program by NWPP.
Resource registration – The process of submitting information to the PO to determine the
QCC of your resource and validating that it meets the RA Program requirements.
Resource QCC – Summation of a Participant’s QCC from its owned resources.
Run-of-river hydro – Hydro resource with less than one hour of storage, not in coordination
with another project.
Safety Margin – A term included in the operational program’s determination of the total
holdback necessary from the RA footprint when a sharing event is forecasted. The PO will
identify this safety margin, based on its understanding of market, weather, outages,
uncertainty, etc. This term is distinctly separate from ‘uncertainty,’ which will be assessed and
included for each other forecasted term. Additional detail can be found in Section 3.3.10.
Sharing Calculation – The set of calculations the PO performs to forecast a Sharing Event
and assign Holdback Requirement to RA Participants. The PO performs the Sharing
Calculation on the preschedule day and any other interim days between the preschedule day
and the OD. The same calculation is used for the Multi-Day Ahead Assessment, though the
results are not binding.
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Sharing Event – When the Sharing Calculation results in at least one RA Participant having a
net negative Sharing Requirement, that Participant is calculated as being deficient and a
Sharing Event is initiated.
Sharing Event Window – The timeframe of a Sharing Event, starting up to one hour before
the first hour in which a RA Participant is calculated as deficient and ending up to one hour
after the RA Participant is no longer calculated deficient.
Sharing Requirement – A result of the Sharing Calculation that represents the maximum MW
amount a RA Participant may be called on by the PO to provide for a given hour of a Sharing
Event. A negative Sharing Requirement indicates that a RA Participant is calculated as being
deficient.
Showing resource – A generating asset or contract registered or claimed on an entity’s FS
portfolio.
Storage hydro – Hydro resource with one hour or greater of storage, not in coordination
with another project.
Storage Hydro QCC Workbook – Analysis tool that employs the methodology used for the
calculation of QCC for Storage Hydro resources
Summer binding season – June 1 through September 15
Thermal resources – Generating resources, such as those fueled by coal or natural gas, in
which heat energy is converted to electricity.
Total RA Transfer – Summation of a Participant’s RA transfer contracts.
Transmission Outages - An outage that may impact path limits and may affect the ability of
a Participant to import firm contracted capacity.
UCAP – Represents the percentage of ICAP available after a unit’s forced outage rate is taken
into account.
Uncontrollable Force – An event or circumstance which prevents one party from performing
its obligations under one or more transactions, which event or circumstance is not within the
reasonable control of, or the result of the negligence of, the claiming party, and which by the
exercise of due diligence the claiming party is unable to avoid, cause to be avoided, or
overcome. This may include such things as flood, drought, earthquake, storm, fire, lightning,
epidemic, war, riot, act of terrorism, civil disturbance or disobedience, labor dispute, material
shortage, sabotage, etc.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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Unit Commitment Service – A capacity and/or associated scheduled energy transaction or a
physically settled option under which the seller has agreed to sell, and the purchaser has
agreed to buy from a specified unit(s) for a specified period, in accordance with the WSPP
Agreement, including Service Schedule B, and any applicable Confirmation.
Variable Energy Resource (VER) – For the purpose of this Program, typically wind and solar
resources.
Western Electricity Coordinating Council (WECC) Prescheduling Calendar – Official
Calendar published on wecc.org that specifies the prescheduling day for each operating day
in a given calendar year.
Western Energy Imbalance Market (EIM) – The California Independent System Operator’s
real-time energy imbalance market.
Winter binding season – November 1 through March 15.
Western Resource Adequacy Agreement (WRAA) – Future agreement that Participants
sign to join the RA Program.
WSPP Service Schedule B – A schedule to the WSPP Power Agreement (WSPP Agreement)
describing additional specific procedures, terms, and conditions for requesting and providing
Unit Commitment Service.
WSPP Service Schedule C – A schedule to the WSPP Power Agreement (WSPP Agreement)
describing additional specific procedures, terms, and conditions for requesting and providing
firm capacity/energy sale or exchange service.
Exhibit No. 6 Case Nos. AVU-E-23-01/AVU-G-23-01 S. Kinney, Avista
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